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Index to Financial Statements
As Filed with the Securities and Exchange Commission on September 2, 2005
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
Energy Transfer Equity, L.P.
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 4922 | 30-0108820 | ||
| (State or other jurisdiction of incorporation or organization) |
(Primary Standard Industrial Classification Code Number) |
(I.R.S. Employer Identification No.) |
Energy Transfer Equity, L.P.
2828 Woodside Street
Dallas, Texas 75204
(214) 981-0700
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
John W. McReynolds
2828 Woodside Street
Dallas, Texas 75204
(214) 981-0700
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
| Thomas P. Mason | G. Michael O’Leary | |
| Vinson & Elkins L.L.P. 1001 Fannin, Suite 2300 Houston, Texas 77002 (713) 758-2222 |
Gislar R. Donnenberg Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200 |
Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective. ¨
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. ¨
CALCULATION OF REGISTRATION FEE
| Title of each class of Securities to be Registered |
Proposed Maximum Aggregate Offering Price |
Amount of Registration Fee | |||||
| Common Units representing limited partner interests |
$ | 345,000,000 | (1)(2) | $ | 40,606.50 | ||
| (1) | Includes common units issuable upon exercise of the underwriters’ over-allotment option. |
| (2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933. |
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
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Index to Financial Statements
The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
| PROSPECTUS |
Subject to completion, dated September 2, 2005. |
Energy Transfer Equity, L.P.
15,000,000 Common Units
Representing Limited Partner Interests
This is an initial public offering of our common units. We are offering a total of 15,000,000 common units. We expect the initial public offering price of these common units to be between $ and $ per common unit.
We own the 2% general partner interest, 50% of the incentive distribution rights and approximately 33% of the outstanding common units of Energy Transfer Partners, L.P. (“ETP”). ETP is a rapidly-growing publicly traded limited partnership engaged in the natural gas midstream, transportation and storage business, with operations in Texas and Louisiana, and in the retail propane marketing business, with operations in 34 states.
Before this offering, there has been no public market for our common units. We intend to list our common units on the New York Stock Exchange under the symbol “ETE.”
Investing in our common units involves risks. See “ Risk Factors” beginning on page 23.
These risks include the following:
| • | Our cash flow will initially consist exclusively of distributions from ETP. |
| • | In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions. |
| • | Our unitholders do not elect our general partner or vote on our general partner’s officers or directors. Following the completion of this offering, affiliates of our general partner will own 86.6% of our common units on a fully diluted basis, a sufficient number to block any attempt to remove our general partner. |
| • | You will experience immediate and substantial dilution of $ per common unit. |
| • | Conflicts of interest exist and may arise among us, our general partner, ETP and any existing or future affiliated entities. |
| • | If ETP is unable to complete acquisitions or construct pipeline extensions on economically acceptable terms or has difficulty integrating newly acquired assets or businesses, our future cash flows could be lower than expected. |
| • | If we or ETP were to be become subject to entity-level taxation for federal or state tax purposes, then our cash available for distribution to you would be substantially reduced. |
| • | Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income. |
| Per Common Unit |
Total | |||||
| Initial Public Offering Price |
$ | $ | ||||
| Underwriting Discount |
$ | $ | ||||
| Proceeds to Energy Transfer Equity (before expenses) |
$ | $ | ||||
We have granted the underwriters a 30-day option to purchase up to an additional 2,250,000 common units on the same terms and conditions as set forth in this prospectus to cover over-allotments of common units, if any.
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the common units on , 2005.
| UBS Investment Bank |
Wachovia Securities | Credit Suisse First Boston |
A.G. Edwards
RBC Capital Markets
Oppenheimer & Co.
Raymond James
Stephens Inc.
, 2005
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| Comparison of Rights of Holders of Our Common Units and ETP’s Common Units |
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| Summary Historical and Pro Forma Financial and Operating Data |
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| OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS |
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| Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA |
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| PARTNERSHIP AGREEMENT PROVISIONS RELATING TO CASH DISTRIBUTIONS |
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| MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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| How Our Partnership Agreement Terms Differ from those of Other Publicly Traded Partnerships |
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| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
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| Material Provisions of Our General Partner’s Limited Liability Company Agreement |
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| MATERIAL PROVISIONS OF ENERGY TRANSFER PARTNERS’ PARTNERSHIP AGREEMENT |
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| F-1 |
| Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. |
A-1 | |||
| Glossary of Terms |
B-1 | |||
You should rely only on the information contained or incorporated by reference in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, offering to sell our common units or seeking offers to buy our common units in any jurisdiction where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common units offered hereby.
Until , 2005 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments and subscriptions.
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This summary may not contain all of the information that is important to you. To understand this offering fully, you should read this entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. Except as otherwise indicated, the information presented in this prospectus assumes that the underwriters do not exercise their over-allotment option. All references in this prospectus to “we,” “us,” “Energy Transfer Equity” and “our” refer to Energy Transfer Equity, L.P. and its subsidiaries, Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P. All references in this prospectus to “our general partner” refer to LE GP, LLC. All references in this prospectus to “Energy Transfer Partners GP” or “ETP GP” refer to Energy Transfer Partners GP, L.P. All references in this prospectus to “Energy Transfer Partners” or “ETP” refer to Energy Transfer Partners, L.P. and its wholly owned subsidiaries and predecessors. All references in this prospectus to ETP’s number of common units, cash distributions, earnings per unit or unit price give effect to ETP’s two-for-one unit split on March 16, 2005.
We are a Delaware limited partnership that currently owns three types of equity interests in Energy Transfer Partners. In addition to indirectly owning the 2% general partnership interest and 50% of the incentive distribution rights in ETP, as of the closing of this offering we will directly own approximately 33% of Energy Transfer Partners’ outstanding common units. ETP is a publicly traded limited partnership that is primarily engaged in the natural gas midstream, transportation and storage business and also has a national retail propane business. As of August 31, 2005, ETP had an equity market capitalization of approximately $4.0 billion, making it the third largest publicly traded master limited partnership in equity market capitalization.
Our aggregate partnership interests in ETP consist of the following:
| • | the 2% general partner interest in ETP, which we hold through our ownership interests in Energy Transfer Partners GP; |
| • | 50% of the outstanding incentive distribution rights in ETP, which we hold through our ownership interests in Energy Transfer Partners GP; and |
| • | approximately 36.4 million common units of ETP (including 3.64 million common units of ETP which we will purchase at the closing of this offering), all of which are held directly by us. |
Our cash flows consist of distributions from ETP on these partnership interests. ETP is required by its partnership agreement to distribute all of its excess cash on hand at the end of each quarter after establishing reserves to provide for the proper conduct of ETP’s business or to provide for future distributions.
ETP has increased its quarterly distribution on its common units 16 times since its initial public offering in 1996. On September 2, 2005, ETP increased the quarterly distribution to $0.50 per unit per quarter for the fiscal quarter ended August 31, 2005 (or $2.00 per unit on an annualized basis). Under ETP’s current capital structure, a distribution of $0.50 per unit of ETP will result in a quarterly distribution to us of approximately $26.4 million in respect of our partnership interests in ETP. We forecast that our partnership interests in ETP will generate $105.4 million in cash to us for the fiscal year ending August 31, 2006, assuming a $2.00 per unit annual distribution.
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Index to Financial Statements
The incentive distribution rights of ETP entitle Energy Transfer Partners GP, as the holder of those rights, to receive the following percentages of cash distributed by ETP as the following target cash distribution levels are reached:
| • | 13.0% of all cash distributed in a quarter after $0.275 has been distributed in respect of each common unit of ETP for that quarter; |
| • | 23.0% of all cash distributed in a quarter after $0.3175 has been distributed in respect of each common unit of ETP for that quarter; and |
| • | the maximum sharing level of 48.0% of all cash distributed in a quarter after $0.4125 has been distributed in respect of each common unit of ETP for that quarter. |
Because we indirectly hold 50% of the outstanding incentive distribution rights in ETP through our ownership interest in Energy Transfer Partners GP, we are entitled to receive 50% of the cash distributed in accordance with the thresholds specified above.
As ETP has increased the quarterly cash distributions paid on its units, we have received increasing payouts on our interests in ETP. These increased cash distributions by ETP have caused the target cash distribution levels described above to be met, thereby increasing the amounts paid by ETP to Energy Transfer Partners GP as the owner of ETP’s incentive distribution rights. As a consequence, our cash distributions from ETP that are based on our indirect ownership of 50% of the incentive distribution rights have increased more rapidly than those based on our ownership of the general partner interest in ETP and ETP common units. Future growth in the distributions that we receive from ETP will not result from an increase in the sharing level associated with the incentive distribution rights as our incentive distribution rights currently participate at the maximum sharing level described above.
The graph set forth below shows hypothetical cash distributions payable in respect of our partnership interests, including the incentive distribution rights in ETP, across an illustrative range of annualized cash distributions per unit made by ETP. This information is based upon:
| • | ETP’s 110,534,514 common units outstanding as of the date of the closing of this offering; and |
| • | our ownership of (1) the 2% general partner interest in ETP, (2) 50% of the incentive distribution rights in ETP and (3) approximately 36.4 million common units of ETP. |
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The graph illustrates the impact to us of ETP raising or lowering its per unit distribution of available cash from operating surplus from the current quarterly distribution of $0.50 per unit, or $2.00 per unit on an annualized basis. This information is presented for illustrative purposes only, is not intended to be a prediction of future performance and does not attempt to illustrate the impact that changes in our business, including changes that may result from changes in interest rates, changes in natural gas prices, changes in general economic conditions, or the impact of any future acquisitions or expansion projects, will have on our performance.
The aggregate amount of ETP’s cash distributions to us will vary depending on several factors, including ETP’s total outstanding partnership interests on the record date for the distribution, the aggregate cash distributions made by ETP and the amount of ETP’s partnership interests we own. If ETP increases distributions to its unitholders, including us, we would expect to increase distributions to our unitholders, although the timing and amount of such increased distributions, if any, will not necessarily be comparable to the timing and amount of the increase in distributions made by ETP. In addition, the level of distributions we receive may be affected by the various risks associated with an investment in us and the underlying business of ETP. Please read “Risk Factors” and “Energy Transfer Partners’ Cash Distribution Policy.”
Our primary business objective is to increase our cash distributions to our unitholders by actively assisting ETP in executing its business strategy. We intend to support ETP in implementing its business strategy by assisting ETP in identifying, evaluating, and pursuing growth opportunities. In the future, we may also support the growth of ETP through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
ETP’s primary objective is to increase the level of its cash distributions over time by pursuing a business strategy that is currently focused on growing its intrastate natural gas midstream business (including transportation, gathering, compression, treating, processing, storage and marketing) and its national propane business through, among other things, pursuing construction and expansion opportunities relating to its existing infrastructure and acquiring additional businesses or assets.
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Index to Financial Statements
ETP has grown significantly through acquisitions and through internal growth projects. The significant acquisitions and internal construction projects that ETP has completed beginning in January 2004 include:
| • | Energy Transfer Transactions. In January 2004, in a series of related transactions, the midstream and transportation operations of La Grange Acquisition, L.P. were combined with the retail propane operations of Heritage Propane Partners, L.P., a publicly traded limited partnership. These transactions, which we refer to as the “Energy Transfer Transactions,” were valued at approximately $1.0 billion and created ETP. Subsequent to these transactions, the combined partnership’s name was changed to Energy Transfer Partners, L.P. |
| • | ET Fuel System. In June 2004, ETP acquired the midstream natural gas assets of TXU Fuel Company (now referred to as the ET Fuel System) from TXU Corp. for approximately $500 million. The ET Fuel System is comprised of approximately 2,000 miles of intrastate natural gas pipelines and related natural gas storage facilities that serve some of the most active natural gas drilling areas in Texas and provide direct access to power plants and interconnects with other intrastate and interstate pipelines that serve major markets. |
| • | East Texas Pipeline. In June 2004, ETP completed the construction of the Bossier Pipeline (now referred to as the East Texas Pipeline). The East Texas Pipeline is a 78-mile natural gas pipeline that provides transportation from the Bossier Sands drilling area in east and north central Texas to ETP’s Southeast Texas System. This pipeline cost approximately $71.4 million to construct. |
| • | Texas Chalk and Madison Systems. In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Energy Corporation for approximately $65.0 million. These systems consist of approximately 1,800 miles of gathering and mainline pipelines, four natural gas treating facilities and a natural gas processing facility located in central Texas near our existing gathering and processing assets. |
| • | Houston Pipeline System. In January 2005, ETP acquired the Houston Pipeline System from American Electric Power Company, Inc. for approximately $825.0 million plus $174.0 million in natural gas inventory, subject to working capital adjustments. This system is comprised of six main transportation pipelines, three market area loops and the largest natural gas storage facility in Texas. |
| • | Fort Worth Basin. In May 2005, ETP completed the construction of the Fort Worth Basin Pipeline, a 55-mile pipeline that provides transportation for natural gas production from the Barnett Shale producing area in north central Texas to ETP’s North Texas Pipeline. This pipeline cost approximately $53.0 million to construct. |
Through these acquisitions and internal growth projects, ETP has created an integrated natural gas transportation and storage system in Texas that facilitates the movement of natural gas from all of the significant natural gas producing areas in Texas to major metropolitan areas in Texas, including Dallas, Houston, Austin and San Antonio, as well as major market hubs and interstate pipelines that transport natural gas to other areas in the United States. This integrated system provides significant opportunities for additional internal growth projects that we believe will generate substantial returns on invested capital without the material execution and commercial risks typically associated with external projects. ETP recently announced approximately $500 million of capital expenditures during the next 12 to 24 months for the two internal growth projects described below.
ETP’s two recently announced major expansion projects involve several pipeline projects that are expected to increase pipeline transportation access for natural gas producers in the Bossier Sands and Barnett Shale basins in east and north Texas to various markets throughout Texas as well as to markets in the eastern United States through interconnects with other intrastate and interstate pipelines. The larger of the two expansion projects is expected to involve the construction of approximately 264 miles of pipeline and the addition of approximately 40,000 horsepower of compression at a cost of approximately $454 million. This expansion project is supported
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by a 10-year agreement with XTO Energy, Inc. pursuant to which XTO Energy has agreed to transport specified volumes of natural gas on an annual basis and is entitled to transport additional volumes under similar terms. ETP’s other major expansion project involves the construction, on a joint venture basis with Atmos Energy Corp., of a 30-inch pipeline in the north Fort Worth Basin area that will provide an additional outlet for natural gas from the Barnett Shale area to several market hubs. These expansion projects will continue the integration of several pipeline systems and natural gas storage facilities, including the integration of ETP’s Katy Pipeline and its Southeast Texas System with the recently acquired ET Fuel System and Houston Pipeline System.
We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. In February 2005, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name to Energy Transfer Equity, L.P. The chart that follows depicts our and our affiliates’ simplified organizational and ownership structure after giving effect to this offering (and based on the ownership of ETP as of the closing of this offering), at which time:
| • | Our general partner will own a 0.5% general partner interest in us. |
| • | Our public unitholders will own 15,000,000 common units representing a 12.9% limited partner interest in us, and our current owners and management will own approximately 100.6 million common units on a fully diluted basis assuming conversion of all outstanding Class B units into common units on a one-for-one basis, representing a 86.6% limited partner interest in us. |
| • | We will own approximately 36.4 million common units of ETP, which will represent approximately 33% of the outstanding common units of ETP at the closing of this offering. This total includes 3.64 million common units of ETP that we intend to purchase from ETP upon the closing of this offering. We intend to fund the purchase of these additional units in part through the net proceeds of this offering and in part through cash contributed to us by our owners prior to the closing of this offering. |
| • | We will hold the 2% general partner interest in ETP through our ownership of equity interests in Energy Transfer Partners GP. |
| • | We will hold 50% of the incentive distribution rights in ETP through our ownership of equity interests in Energy Transfer Partners GP. |
The remaining 50% of the incentive distribution rights in ETP are held by Energy Transfer Investments, L.P., or ETI, through its ownership interests in Energy Transfer Partners GP. Our general partner, which is owned by Ray C. Davis, Kelcy L. Warren and Natural Gas Partners VI, L.P., also owns 100% of the general partner interest of the limited partnership that is the general partner of ETI.
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Our general partner, LE GP, LLC, will manage our operations and activities. Some of the non-independent directors of our general partner also serve as directors of the general partner of ETP. Please read “Management.” Our general partner will receive a management fee of $500,000 per year for its management of our business and will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. In addition, we will enter into a shared services agreement with ETP in connection with the closing of this offering, pursuant to which ETP will provide substantially all employees and financial, accounting, administrative, legal and other services to us. Pursuant to the shared services agreement, we will pay ETP a fixed annual fee of approximately $500,000 and reimburse ETP at cost for all services provided to us. Please read “Certain Relationships and Related Party Transactions—Shared Services Agreement.”
Our Principal Executive Offices
Our principal executive offices are located at 2828 Woodside Street, Dallas, Texas 75204, and our telephone number at that location is (214) 981-0700.
Energy Transfer Partners, L.P.
ETP is primarily engaged in the natural gas midstream, transportation and storage business and the retail propane business. ETP was originally formed as Heritage Propane Partners, L.P., a master limited partnership that completed its initial public offering in 1996. In January 2004, the propane operations of Heritage Propane Partners were combined with the natural gas midstream and transportation business of La Grange Acquisition, L.P. In March 2004, the combined entity’s name was changed to Energy Transfer Partners, L.P. As of August 31, 2005, ETP was the third largest publicly traded master limited partnership in the United States by equity market capitalization.
ETP’s natural gas midstream, transportation and storage operations are primarily located in major natural gas producing regions of Texas and Louisiana. These operations consist of approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to ETP’s gathering systems, 14 natural gas treating facilities and three natural gas storage facilities. The midstream business of ETP focuses on the gathering, compression, treating, processing and marketing of natural gas and is currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Bossier Sands area in east Texas and the Barnett Shale in north Texas. ETP owns or has an interest in various other midstream assets located in east Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, the Dorado System and the Chalkley Transmission System. The transportation and storage business of ETP focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through the Oasis Pipeline, the East Texas Pipeline System, the ET Fuel System, the Houston Pipeline System and the recently completed Fort Worth Basin Pipeline, all of which are located in Texas. ETP is also the fourth largest retail propane marketer in the United States, having propane operations which serve more than 700,000 customers in 34 states, primarily in the western, upper midwestern, northeastern and southeastern regions of the United States.
ETP’s business strategies are to:
| • | continue to focus on its intrastate natural gas transportation and storage operations; |
| • | leverage its existing midstream infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream services; |
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| • | make strategic acquisitions of midstream and transportation assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of its existing and acquired assets; |
| • | increase the profitability of its existing midstream asset base by adding new volumes of natural gas, undertaking additional initiatives to enhance utilization and reducing costs by improving operations; |
| • | increase its fee-based cash flow in its midstream, natural gas transportation and natural gas storage businesses; |
| • | grow its retail propane business through complementary acquisitions; and |
| • | enhance its propane business by maintaining low-cost, decentralized operations. |
ETP is a limited partnership formed under the laws of the State of Delaware. Its executive offices are located at 2838 Woodside Street, Dallas, Texas 75204 and its telephone number at that location is (214) 981-0700. ETP maintains a website at http://www.energytransfer.com that provides information about its business and operations. Information contained on this website, however, is not incorporated into or otherwise a part of this prospectus. ETP also files annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. ETP’s Commission filings are available to the public over the Internet at the Commission’s website at http://www.sec.gov. You may also read and copy any document ETP files at the Commission’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Commission’s public reference room by calling the Commission at 1-800-SEC-0330.
Comparison of Rights of Holders of Our Common Units and ETP’s Common Units
Our common units and ETP’s common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our common units and ETP’s common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:
| • | ETP’s cash distributions to its common unitholders have a priority over our incentive distribution rights in ETP; |
| • | we participate in ETP’s general partner’s distributions and the incentive distribution rights, and ETP’s common unitholders do not; and |
| • | we may enter into other businesses separate from ETP or any of its affiliates. See “—Our Interests in ETP.” |
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The following table compares certain features of ETP’s common units and our common units.
| ETP’s Common Units |
Our Common Units | |||
| Taxation of Entity and Entity Owners | ETP is a flow-through entity that is not subject to an entity-level federal income tax.
ETP common unitholders will be allocated an amount of federal taxable income for the cumulative period ending December 31, 2008 related to ETP’s operations that is expected to be less than the cumulative amount of cash distributions that they receive with respect to that period.
ETP common unitholders will receive Schedule K-1s from ETP reflecting the unitholders’ share of ETP’s items of income, gain, loss and deduction at the end of each fiscal year. |
Similarly, we are a flow-through entity that is not subject to an entity-level federal income tax.
Similarly, our common unitholders will be allocated an amount of federal income tax for the cumulative period ending December 31, 2008 related to our operations that is expected to be less than the amount of cash distributions that they receive with respect to that period, although the ratio of taxable income allocated to our unitholders in relation to our cash distributions will be less than the ratio of taxable income allocated to ETP’s unitholders in relation to its cash distributions.
Our common unitholders also will receive Schedule K-1s from us reflecting the unitholders’ share of our items of income, gain, loss and deduction at the end of each fiscal year.
| ||
| Sources of Cash Flow | ETP is our subsidiary and may engage in acquisition and development activities that expand its business and operations. | Our cash-generating assets consist of our partnership interests in ETP, including incentive distribution rights, and we currently have no independent operations. Accordingly, our financial performance and our ability to pay cash distributions to our unitholders is currently directly dependent upon the performance of ETP. | ||
| Limitation on Issuance of Additional Units | ETP may issue an unlimited number of additional partnership interests and other equity securities without obtaining unitholder approval. | Similarly, we may issue an unlimited number of additional partnership interests and other equity securities without obtaining unitholder approval. | ||
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Index to Financial Statements
An investment in our units involves risks. These risks include, but are not limited to, those described below. For a more complete description of the risks we face, see “Risk Factors.”
Risks Inherent in an Investment in Us
| • | Our only assets at the closing of this offering will be our partnership interests in ETP and therefore our cash flow initially will be completely dependent upon the ability of ETP to make distributions in respect of those partnership interests. |
| • | In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions. |
| • | Following the completion of this offering, affiliates of our general partner will own 86.6% of our common units on a fully diluted basis, a sufficient number to change our cash distribution policy, amend our partnership agreement and block any attempt to remove our general partner. |
| • | You will experience immediate and substantial dilution of $20.69 per unit. |
| • | The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders. |
| • | The control of our general partner and the limited partnership that indirectly holds the other 50% of the incentive distribution rights in ETP may be transferred to a third party without unitholder consent. |
| • | Our general partner only has one executive officer, and we are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative, legal and other services necessary to operate our business. |
Risks Related to ETP’s Business
| • | The profitability of ETP’s midstream, transportation and storage business is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which factors are beyond ETP’s control and have been volatile. |
| • | ETP’s success depends upon its ability to continually contract for new sources of natural gas supply. |
| • | ETP may be unable to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for qualified assets. |
| • | If ETP does not make acquisitions on economically acceptable terms, its future growth could be limited. |
| • | ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System, and the loss of any of these key producers could adversely affect its financial results. |
| • | ETP depends on key customers to transport natural gas on its East Texas Pipeline and ET Fuel System. |
| • | Federal, state or local regulatory measures could adversely affect ETP’s business. |
| • | ETP’s business involves hazardous substances and may be adversely affected by environmental regulation. |
| • | Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect its revenues and cash flow. |
| • | ETP encounters competition from other midstream, transportation and storage companies and propane companies. |
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Index to Financial Statements
| • | Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks. |
| • | ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its unitholders, including us. |
| • | ETP may be unable to bypass the La Grange processing plant, which could expose it to the risk of unfavorable processing margins. |
| • | ETP may be unable to retain existing customers or secure new customers, which would reduce its revenues and limit its future profitability. |
| • | ETP’s storage business depends on neighboring pipelines to transport natural gas. |
| • | ETP’s pipeline integrity program may cause it to incur significant costs and liabilities. |
| • | Because weather conditions may adversely affect demand for propane, the volumes of propane sold by and the results of operations of ETP’s propane business are vulnerable to warm winters. |
| • | Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect the profit margins of ETP’s propane business. |
| • | ETP’s results of operations and its ability to make distributions or pay interest or principal on debt securities could be negatively impacted by price and inventory risk related to its propane business and management of these risks. |
| • | ETP’s propane business depends on its principal propane suppliers, which increases the risk of an interruption in supply. |
| • | Competition from alternative energy sources may cause ETP to lose propane customers, thereby reducing its revenues. |
| • | Energy efficiency and technological advances may affect the demand for propane and adversely affect ETP’s operating results. |
Risks Related to Conflicts of Interest
| • | Although we control ETP through our ownership of its general partner, ETP’s general partner owes fiduciary duties to ETP and ETP’s unitholders, which may conflict with our interests. |
| • | Our general partner’s affiliates, including the partnership that indirectly holds the other 50% of ETP’s incentive distribution rights, may compete with us. |
| • | Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. |
| • | Our general partner has a limited call right that may require you to sell your units at an undesirable time or price. |
| • | ETP may issue additional ETP units, which may increase the risk that ETP will not have sufficient available cash to maintain or increase its per unit distribution level. |
| • | If we or ETP were to become subject to entity-level taxation for federal or state tax purposes, then our cash available for distribution to you would be substantially reduced. |
| • | A successful IRS contest of the federal income tax positions we or ETP take may adversely impact the market for our common units or ETP common units, and the costs of any contest will reduce cash available for distribution to our unitholders. |
| • | Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income. |
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Index to Financial Statements
| Common units offered by Energy Transfer Equity |
15,000,000 common units or 17,250,000 common units if the underwriters exercise their over-allotment option in full. |
| Common units outstanding after this offering |
115,560,061 common units (on a fully diluted basis assuming conversion of all outstanding Class B units that are convertible into common units on a one-for-one basis). |
| Use of proceeds |
We will use a portion of the net proceeds from this offering, in addition to cash from a capital contribution of $119.7 million to be made by our equity owners prior to the closing of this offering: |
| • | to repay approximately $240 million of indebtedness outstanding under our term loan facility; |
| • | to fund the acquisition of an additional 3.64 million ETP common units; and |
| • | for general partnership purposes. Please read “Use of Proceeds.” |
| • | If the underwriters exercise all or any portion of their over-allotment option, we will use all of the net proceeds from the sale of our common units sold pursuant to the exercise of that option to fund the redemption of an equal number of common units from our current equity owners. |
| An affiliate of Wachovia Securities Capital Markets, LLC, an underwriter in this offering, is a lender under our term loan facility and will be repaid with a portion of the net proceeds of this offering. Please read “Underwriting.” |
| Cash distributions |
We intend to make an initial quarterly distribution of $0.175 per common unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and ETP. In general, we will initially distribute 99.5% of our available cash each quarter to the holders of common units and Class B units and 0.5% of our available cash to our general partner. |
| We expect to pay you a prorated distribution for the first quarter during which we are a publicly traded partnership. This distribution would be paid for the period beginning on the first day our common units are publicly traded and ending on the last day of that fiscal quarter. Therefore, assuming that we become a publicly traded partnership after November 30, 2005 and before February 28, 2006, we would pay you a distribution for the period from the first day our common units are publicly traded to and including February 28, 2006. However, we cannot assure you that any distributions will be declared or paid. |
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Index to Financial Statements
| We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B. The amount of available cash may be greater than or less than the initial quarterly distribution. |
| We believe that, based on the assumptions described under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash from operations to make the initial quarterly distribution of $0.175 per unit on all units for each quarter through August 31, 2006. The amount of pro forma, as adjusted, cash available for distribution generated during the year ended August 31, 2004 and for the nine months ended May 31, 2005 would have been more than sufficient to allow us to fully pay the initial quarterly distribution on our common units. Please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 47 of this prospectus. |
| Issuance of additional units |
We may issue an unlimited number of common units in the future on terms and conditions established by our general partner without unitholder approval. Our general partner is not required to make additional capital contributions to us in connection with issuances by us of additional units. To the extent our general partner does not make additional capital contributions to us when we issue additional units, its general partner interest in us will be proportionately reduced. |
| Limited call right |
If at any time our affiliates own more than 90% of our outstanding units, our general partner has the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units. |
| Limited voting rights |
Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its officers or directors. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, affiliates of our general partner will own approximately 86.6% of our outstanding common units and Class B units. This ownership level will enable our general partner and these affiliates to prevent our general partner’s involuntary removal. Please read “Description of Our Partnership Agreement—Withdrawal or Removal of Our General Partner.” |
| Estimated ratio of taxable income to distributions |
We estimate that if you own the common units you purchase in this offering through December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period |
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Index to Financial Statements
| that will be less than % of the cash distributed with respect to that period. This estimate is based on an assumed quarterly distribution of $0.175 per our common unit and other assumptions with respect to our operations, gross income, capital expenditures, cash flow and anticipated distributions. Moreover, if ETP is successful in increasing its distributions over time, our ratio of taxable income to cash distributions will increase. For the basis of this estimate, please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.” |
| Exchange listing |
We intend to list our common units on the New York Stock Exchange under the symbol “ETE.” |
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Index to Financial Statements
Summary of Conflicts of Interest and Fiduciary Duties
Conflicts of Interest. Conflicts of interest exist and may arise in the future as a result of the relationships among us, ETP and our and their respective general partners and affiliates. The owners of our general partner are Ray C. Davis, Kelcy L. Warren and Natural Gas Partners VI, L.P. These owners also control Energy Transfer Investments, L.P., which holds 50% of the incentive distribution rights in ETP through its ownership of equity interests in the general partner of ETP. Natural Gas Partners VI, L.P., which we refer to as the “NGP Fund,” is a private equity fund that owns a significant portion of our equity securities and has the right to appoint two directors to the board of directors of our general partner. Mr. Davis and Mr. Warren are the co-chairmen and co-chief executive officers of ETP and also own significant portions of the entities that hold our equity securities. Mr. Davis, Mr. Warren and the NGP Fund have all been involved with ETE since our inception in 2002.
Our partnership agreement specifically permits us and our affiliates to engage in any activity, including those that may be in direct competition with ETP. As a result, either we or our affiliates may acquire, construct or dispose of natural gas midstream, transportation and storage or propane assets without any obligation to offer ETP the opportunity to acquire those assets. However, because we have a strong incentive to support the growth of ETP due to our significant ownership interest in ETP, we may offer such assets to ETP if they are complementary to ETP’s strategy or operations. Currently, ETP is not prohibited from engaging in any activity that may compete with us. In the event that we desire to sell any assets to ETP, the corporate governance policies of ETP provide that no such sale may occur unless the purchase by ETP is approved by the audit committee of the ETP board (a committee that satisfies the independence requirements of the New York Stock Exchange) or the purchase by ETP is equitable to ETP, taking into account the totality of the relationships between the parties.
Fiduciary Duties. Our general partner’s directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. Our general partner’s directors also have fiduciary duties to its equity owners. Some of the non-independent directors of our general partner also serve as directors of Energy Transfer Partners GP and, as a result, have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and its partners. Consequently, these directors may encounter situations in which their fiduciary obligations to ETP, on the one hand, and us and our equity owners, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving our general partner and the resolution of these conflicts, please read “Conflicts of Interest and Fiduciary Duties.”
Our partnership agreement limits our general partner’s liability for breaches of its fiduciary duty to us and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duty owed to unitholders. By purchasing our common units, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.
Shared Personnel. Our general partner will manage our operations and activities with assistance from ETP. In connection with the closing of this offering, we will enter into a shared services agreement between Energy Transfer Partners GP and ETP. Under the shared services agreement, personnel of ETP will perform administrative and commercial services for us. The services performed by these personnel will include, but not be limited to, financial, accounting, administrative, legal and other services. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us and ETP. For a more detailed description of our shared services agreement, please read “Certain Relationships and Related Party Transactions—Shared Services Agreement.”
For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”
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Index to Financial Statements
Summary Historical and Pro Forma Financial and Operating Data
The table on the following page shows summary historical consolidated and pro forma financial data for Energy Transfer Equity, L.P., in each case for the periods and as of the dates indicated. The summary historical consolidated statement of operations and cash flow data for the eleven months ended August 31, 2003 and the year ended August 31, 2004 and the balance sheet data as of August 31, 2003 and 2004 are derived from our audited financial statements. The selected historical statement of operations and cash flow data for the nine months ended September 30, 2002 and balance sheet data as of September 30, 2002 are derived from the audited financial statements of Aquila Gas Pipeline, the predecessor to Energy Transfer Partners. The statement of operations, balance sheet, and cash flow data as of and for the nine months ended May 31, 2004 and 2005, are derived from our unaudited financial statements. The unaudited financial statements include all adjustments, consisting of normal, recurring accruals, which we consider necessary for the fair presentation of our financial position and results of operations for these periods.
We have not had any separate operating activities apart from those conducted by ETP, and at present our cash flows solely consist of distributions from ETP on the partnership interests, including incentive distribution rights, that we own. Accordingly, the summary historical consolidated financial data set forth in the table on the following page primarily reflect the operating activities and results of operations of ETP. Since we control ETP, we reflect our ownership interest in ETP on a consolidated basis, which means that our financial results are combined with ETP’s financial results and the results of our other subsidiaries. The interest owned by non-controlling partners in ETP is reflected as a liability on our balance sheet and the non-controlling partners’ shares of income from ETP is reflected as an expense in our results of operations.
The unaudited summary pro forma statement of operations data for the year ended August 31, 2004 and for the nine months ended May 31, 2005 reflect our consolidated historical operating results as adjusted to give pro forma effect to the following transactions as if these transactions occurred on September 1, 2003:
| • | our business combination in January 2004 with Heritage Propane Partners, L.P., which we refer to as “Heritage;” |
| • | the acquisition in June 2004 by ETP of the TXU Fuel Company from TXU Corp. and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | the acquisition in January 2005 by ETP of the controlling interests in the companies that own the Houston Pipeline System and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | our new term loan in the aggregate principal amount of $600.0 million, the payment of related expenses and the distribution of the net proceeds of such borrowings to our unitholders in June 2005; |
| • | the transfer of class B limited partner interests in ETP GP to Energy Transfer Investments and to us, which entitle ETI and us to each receive 50% of the cash distributions attributable to the ownership of ETP’s incentive distribution rights; |
| • | a capital contribution of $119.7 million to be made by our equity owners prior to the closing of this offering; and |
| • | this offering and the application of the net proceeds of $266.3 million and the related expenses as described under “Use of Proceeds.” |
The unaudited pro forma summary balance sheet data as of May 31, 2005 reflect our consolidated historical balance sheet data as adjusted to give pro forma affect to the following transactions, in each case as if the following transactions occurred on May 31, 2005:
| • | our new term loan in the aggregate principal amount of $600.0 million, the payment of related expenses and the distribution of the net proceeds of such borrowings to our unitholders in June 2005; |
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| • | the transfer of class B limited partner interests in ETP GP to Energy Transfer Investments and to us, which entitle ETI and us to each receive 50% of the cash distributions attributable to the ownership of ETP’s incentive distribution rights; |
| • | a capital contribution of $119.7 million to be made by our equity owners prior to the closing of this offering; and |
| • | this offering and the application of the net proceeds of $266.3 million and the related expenses as described under “Use of Proceeds.” |
For a description of all of the assumptions used in preparing the summary pro forma financial and operating data, you should read the notes to the pro forma financial statements for Energy Transfer Equity, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after this offering.
We derived the data in the following table from, and it should be read together with and is qualified in its entirety by reference to, the historical consolidated and pro forma financial statements and the accompanying notes included in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| Historical (a) |
Pro Forma |
|||||||||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity |
|||||||||||||||||||||||||||
| Nine Months Ended September 30, 2002 |
Eleven Months August 31, 2003 |
Year 2004 |
Nine Months Ended May 31, |
Year Ended August 31, 2004 |
Nine Months Ended May 31, 2005 |
|||||||||||||||||||||||
| 2004 |
2005 |
|||||||||||||||||||||||||||
| (in thousands, except per unit data) | ||||||||||||||||||||||||||||
| Statement of Operations Data: |
||||||||||||||||||||||||||||
| Revenues |
$ | 933,099 | $ | 931,027 | $ | 2,346,957 | $ | 1,591,656 | $ | 4,335,791 | $ | 6,350,022 | $ | 6,004,015 | ||||||||||||||
| Gross profit |
53,035 | 105,589 | 365,533 | 245,809 | 579,713 | 679,026 | 665,189 | |||||||||||||||||||||
| Depreciation and amortization |
22,915 | 11,870 | 56,242 | 32,793 | 76,874 | 105,676 | 85,534 | |||||||||||||||||||||
| Operating income |
2,862 | 55,501 | 130,806 | 106,999 | 234,904 | 219,490 | 275,529 | |||||||||||||||||||||
| Interest expense |
(3,931 | ) | (12,453 | ) | (41,217 | ) | (25,111 | ) | (66,350 | ) | (119,709 | ) | (99,631 | ) | ||||||||||||||
| Gain on Energy Transfer Transactions |
— | — | 395,253 | 320,893 | — | — | — | |||||||||||||||||||||
| Minority interests on continuing operations |
— | — | (35,164 | ) | (32,170 | ) | (91,439 | ) | (76,122 | ) | (114,745 | ) | ||||||||||||||||
| Income from continuing operations before income taxes |
4,272 | 44,673 | 449,551 | 371,282 | 70,047 | 26,064 | 58,459 | |||||||||||||||||||||
| Income tax (benefit) expense (c) |
(467 | ) | 4,432 | 2,792 | 3,861 | 5,168 | 5,273 | 5,776 | ||||||||||||||||||||
| Income from continuing operations |
$ | 4,739 | $ | 40,241 | $ | 446,759 | $ | 367,421 | $ | 64,879 | $ | 29,791 | $ | 52,683 | ||||||||||||||
| Basic income from continuing operations share/unit (d) |
— | $ | 0.25 | $ | 2.47 | $ | 2.10 | $ | 0.33 | $ | 0.18 | $ | 0.45 | |||||||||||||||
| Distributions share/unit (d) |
— | — | $ | 2.49 | $ | 2.11 | $ | 0.62 | $ | 0.18 | $ | 0.45 | ||||||||||||||||
| Balance Sheet Data (end of period): |
||||||||||||||||||||||||||||
| Total assets |
$ | 601,528 | $ | 604,140 | $ | 2,865,193 | $ | 2,247,760 | $ | 4,522,355 | $ | 4,775,394 | ||||||||||||||||
| Current liabilities |
144,076 | 169,967 | 404,917 | 1,018,670 | 1,015,618 | 1,015,618 | ||||||||||||||||||||||
| Long-term debt |
66,250 | 196,000 | 1,071,158 | 698,343 | 1,570,155 | 1,870,155 | ||||||||||||||||||||||
| Stockholders’ equity/partners’ capital |
254,259 | 182,631 | 368,325 | 307,619 | 423,975 | 270,440 | ||||||||||||||||||||||
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| Historical (a) |
||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity |
|||||||||||||||||||
| Nine Months Ended September 30, 2002 |
Eleven Months Ended August 31, 2003 |
Year Ended August 31, 2004 |
Nine Months Ended May 31, |
|||||||||||||||||
| 2004 |
2005 |
|||||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Other Financial Data: |
||||||||||||||||||||
| EBITDA, as adjusted (unaudited) (e) |
$ | 31,118 | $ | 77,382 | $ | 158,436 | $ | 111,715 | $ | 218,211 | ||||||||||
| Net cash provided by operating activities |
12,987 | 70,675 | 122,098 | 135,180 | 216,850 | |||||||||||||||
| Net cash used in investing activities |
(487 | ) | (341,258 | ) | (731,831 | ) | (210,279 | ) | (1,038,645 | ) | ||||||||||
| Net cash provided by (used in) financing activities |
(12,500 | ) | 325,655 | 637,513 | 86,445 | 760,550 | ||||||||||||||
| (a) | We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. On January 20, 2004, we and Heritage completed a series of transactions which, among other things, included: |
| • | we contributed our subsidiary La Grange Acquisition, L.P., and its subsidiaries and affiliates who conducted business under the assumed name of Energy Transfer Company, or ETC OLP, to Heritage in exchange for cash, the assumption of certain liabilities and three classes of securities; and |
| • | we acquired the general partner of Heritage from its owners. |
We refer to these transactions as the “Energy Transfer Transactions.” The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETP was the acquirer for accounting purposes. As a result, our historical financial statements are the historical financial statements of the combined company. In February 2005, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name to Energy Transfer Equity, L.P.
| (b) | On December 27, 2002, we purchased the remaining 50% of Oasis Pipe Line Company. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After that date, Oasis Pipe Line’s results of operations were consolidated with our results of operations as a wholly owned subsidiary. |
| (c) | As a partnership, we are not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings, Inc. and Heritage Service Corporation, are corporations that are subject to income taxes. Prior to 2003, Oasis Pipe Line was an equity method investment of ETC OLP, and taxes were netted against the equity method earnings. Aquila Gas Pipeline was a tax-paying corporation, and as such recognized income taxes related to its earnings in all periods presented. |
| (d) | Net income per unit is computed by dividing the limited partners’ interest in net income by the weighted average number of units outstanding. |
| (e) | EBITDA, as adjusted, is defined as our earnings before interest, taxes, depreciation (adjusted for depreciation directly attributable to minority interests), amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, gain or loss on discontinued operations (net of minority interests), gain on the Energy Transfer Transactions and other expenses. We present EBITDA, as adjusted, on a partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the common units awarded under ETP’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the gain or loss arising from our disposal of assets, discontinued operations, and the gain on the Energy Transfer Transactions are not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements. |
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Index to Financial Statements
EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of the partnership’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to our investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA, as adjusted, allows investors to view the partnership’s performance in a manner similar to the methods used by management and provides additional insight to our operating results.
EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full partnership basis, we add back the minority interest of the general partner because net income per limited partner unit is reported net of the general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of our business. The inclusion of these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ETP’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in the partnership’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted, since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read Note 5 to our consolidated financial statements included in this prospectus.
There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, our calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by us in the past. Management compensates for these limitations by considering EBITDA, as adjusted, in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities. A reconciliation of EBITDA, as adjusted, to net income (loss) is presented below. Please read “Reconciliation of EBITDA, As Adjusted, to Net Income” below.
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Reconciliation of EBITDA, as Adjusted, to Net Income
The following tables set forth the reconciliation of EBITDA, as adjusted, to our net income for the periods indicated:
| Historical |
||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity |
|||||||||||||||||||
| Nine Months Ended September 30, 2002 |
Eleven Months Ended August 31, 2003 |
Year Ended August 31, 2004 |
Nine Months Ended May 31, |
|||||||||||||||||
| 2004 |
2005 |
|||||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Net income |
$ | 4,739 | $ | 46,235 | $ | 450,217 | $ | 369,774 | $ | 121,879 | ||||||||||
| Gain on Heritage Transaction |
— | — | (395,253 | ) | — | |||||||||||||||
| Gain on sale of discontinued operations, net of income tax expense |
— | — | — | (320,893 | ) | (104,562 | ) | |||||||||||||
| Minority interest expense on gain on sale of discontinued operations |
— | — | — | — | 49,686 | |||||||||||||||
| Depreciation and amortization |
22,915 | 11,870 | 56,242 | 32,794 | 76,874 | |||||||||||||||
| Interest expense |
3,931 | 12,453 | 41,217 | 25,111 | 66,350 | |||||||||||||||
| Income tax expense on continuing operations |
(467 | ) | 4,432 | 2,792 | 3,861 | 5,168 | ||||||||||||||
| Non-cash compensation expense |
— | — | 42 | — | 1,206 | |||||||||||||||
| Interest income and other |
— | (202 | ) | (516 | ) | (400 | ) | (67 | ) | |||||||||||
| (Gain) loss on disposal of assets |
— | 1,006 | 235 | 665 | ||||||||||||||||
| Minority interests |
— | — | — | — | ||||||||||||||||
| Equity in earnings of investees |
— | 1,003 | — | |||||||||||||||||
| Depreciation, amortization and interest of investee |
— | 440 | 315 | 493 | ||||||||||||||||
| Depreciation, amortization and interest of discontinued operations |
— | 1,591 | 2,249 | 918 | 1,547 | |||||||||||||||
| Depreciation, amortization and interest of minority interest |
— | — | — | — | (7,578 | ) | ||||||||||||||
| Loss on extinguishment of debt |
— | — | — | — | 6,550 | |||||||||||||||
| EBITDA, as adjusted |
$ | 31,118 | $ | 77,382 | $ | 158,436 | $ | 111,715 | $ | 218,211 | ||||||||||
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This prospectus contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
| • | the amount of natural gas transported on ETP’s pipelines and gathering systems; |
| • | the level of throughput in ETP’s natural gas processing and treating facilities; |
| • | the fees ETC OLP charges and the margins realized for its services; |
| • | the prices and market demand for, and the relationship between, natural gas and NGLs; |
| • | energy prices generally; |
| • | the price of propane to the consumer compared to the price of alternative and competing fuels; |
| • | the general level of petroleum product demand and the availability and price of propane supplies; |
| • | the level of domestic oil, propane and natural gas production; |
| • | the availability of imported oil and natural gas; |
| • | the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas; |
| • | actions taken by foreign oil and gas producing nations; |
| • | the political and economic stability of petroleum producing nations; |
| • | the effect of weather conditions on demand for oil, natural gas and propane; |
| • | availability of local, intrastate and interstate transportation systems; |
| • | the continued ability to find and contract for new sources of natural gas supply; |
| • | availability and marketing of competitive fuels; |
| • | the impact of energy conservation efforts; |
| • | energy efficiencies and technological trends; |
| • | the extent of governmental regulation and taxation; |
| • | hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance; |
| • | the maturity of the propane industry and competition from other propane distributors; |
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| • | competition from other midstream companies; |
| • | loss of key personnel; |
| • | loss of key natural gas producers or the providers of fractionation services; |
| • | reductions in the capacity or allocations of third party pipelines that connect with ETP’s pipelines and facilities; |
| • | the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments; |
| • | the nonpayment or nonperformance by ETP’s customers; |
| • | regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems; |
| • | the availability and cost of capital and ETP’s ability to access certain capital sources; |
| • | changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations; |
| • | the costs and effects of legal and administrative proceedings; |
| • | the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses; and |
| • | risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities. |
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus.
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Risks Inherent in an Investment in Us
Our only assets at the closing of this offering will be our partnership interests in ETP and therefore our cash flow initially will be completely dependent upon the ability of ETP to make distributions in respect of those partnership interests.
The amount of cash that ETP can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
| • | the amount of natural gas transported in its pipelines and gathering systems; |
| • | the throughput volumes in its natural gas processing and treating facilities; |
| • | the fees it charges and the margins it realizes for its services; |
| • | prices of natural gas and propane; |
| • | relationships among crude oil, natural gas and NGL prices; |
| • | weather conditions; |
| • | the level of its operating costs, including reimbursements to its general partner; and |
| • | prevailing economic conditions. |
In addition, the actual amount of cash that ETP will have available for distribution will depend on other factors, including:
| • | the level of capital expenditures it makes; |
| • | the sources of cash used to fund its acquisitions; |
| • | its debt service requirements and restrictions contained in its obligations for borrowed money; |
| • | fluctuations in its working capital needs; and |
| • | the amount of cash reserves established by Energy Transfer Partners GP for the proper conduct of ETP’s business. |
Because of these factors, ETP may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. Furthermore, the amount of cash that ETP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ETP may be able to make cash distributions during periods when it records losses and may be unable to make cash distributions during periods when it records net income. Please read “—Risks Related to Energy Transfer Partners’ Business” for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.
In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions.
The source of our earnings and cash flow will initially consist exclusively of cash distributions from ETP. Therefore, the amount of distributions we are able to make to our unitholders may fluctuate based on the level of distributions ETP makes to its partners. We cannot assure you that ETP will continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if ETP increases or decreases distributions to us,
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the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP to us.
Our ability to distribute cash received from ETP to our unitholders is limited by a number of factors, including:
| • | interest expense and principal payments on our indebtedness; |
| • | restrictions on distributions contained in any current or future debt agreements; |
| • | our general and administrative expenses, including expenses we will incur as the result of being a public company; |
| • | expenses of our subsidiaries other than ETP, including tax liabilities of our corporate subsidiaries, if any; |
| • | capital contributions to maintain our 2% general partner interest in ETP as required by the partnership agreement of ETP upon the issuance of additional partnership securities by ETP; and |
| • | reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions. |
We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our estimated initial quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.
Following the completion of this offering, affiliates of our general partner will own 86.6% of our common units on a fully diluted basis, a sufficient number to change our cash distribution policy, amend our partnership agreement and block any attempt to remove our general partner.
Following completion of this offering, our current owners will own approximately 86.6% of our outstanding common units on a fully diluted basis. In addition, some of these owners will be members of the board of directors of our general partner. Because our current owners will have the ability to amend our partnership agreement and change our cash distribution policy after this offering, we cannot assure you that we will maintain or increase the distribution we pay to our common unitholders.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner.
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding units. Because affiliates of our general partner own approximately 100.6 million of our outstanding units, it will be particularly difficult for our general partner to be removed without the consent of such affiliates. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
A reduction in ETP’s distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.
Our ownership of 50% of the incentive distribution rights in ETP, through our ownership of equity interests in Energy Transfer Partners GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash
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distribution levels. The amounts of the cash distributions that we received from ETP related to our ownership interest in the incentive distribution rights has increased at a more rapid rate than the amounts of the cash distributions related to our 2% general partner interest in ETP and our ETP common units. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which Energy Transfer Partners GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per common unit per quarter would reduce Energy Transfer Partners GP’s percentage of the incremental cash distributions above $0.3175 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our 2% general partner interest in ETP and our ETP common units.
Neither we nor ETP will be prohibited from competing with each other.
Neither our partnership agreement nor the partnership agreement of ETP prohibits us from owning assets or engaging in businesses that compete directly or indirectly with ETP or prohibit ETP from owning assets or engaging in businesses that compete directly or indirectly with us, except that ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, we may acquire, construct or dispose of any assets in the future without any obligation to offer ETP the opportunity to purchase or construct any of those assets, and ETP may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of these assets. Please read “Certain Relationships and Related Party Transactions.”
Restrictions in our credit facility could limit our ability to make distributions to our unitholders.
Our term loan facility contains affirmative covenants relating to, among other things: delivery of financial statements and other reports, including compliance certificates and notice of specified events; maintenance of existence; payment of taxes and claims; maintenance of property and insurance; lender inspection rights; compliance with law, including environmental laws; subsidiary guarantee and security obligations; further assurances; use of proceeds; separateness of ETP; payment of contractual or debt obligations; and subsidiaries. Our term loan facility also contains negative covenants relating to, among other things: incurrence of indebtedness; liens; restricted payments; and restrictions on subsidiary distributions; investments; fundamental changes; dispositions of assets; acquisitions; capital expenditures; sale and lease-back transactions; transactions with affiliates; conduct of business; changes in fiscal year or in tax status; and amendments or waivers of certain agreements or material contracts. This term loan facility also contains covenants requiring us to maintain certain financial ratios. We will be prohibited from making any distributions to our unitholders if the distributions would cause an event of default or otherwise violate a covenant under this term loan facility. For more information about our term loan facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Obligations—Energy Transfer Equity.”
Our existing term loan prohibits us from borrowing more than $100.0 million of incremental indebtedness, which prohibition may restrict our ability to pursue business opportunities.
Our existing term loan facility prohibits us from borrowing more than $100.0 million of incremental indebtedness, which may restrict our ability to pursue business opportunities that we would want to finance, either in whole or in part, from borrowings rather than from the issuance of additional equity securities, the use of internal cash flow or other financing arrangements.
You will experience immediate and substantial dilution of $20.69 per unit.
The assumed initial public offering price of $19.00 per unit exceeds our pro forma net tangible book value of ($1.69) per unit after the offering. You will incur immediate and substantial dilution of $20.69 per unit. Please read “Dilution.”
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We may issue an unlimited number of limited partner interests without the consent of our unitholders, which would dilute your ownership interest in us and could increase the risk that we would not have sufficient available cash to maintain or increase our per unit distribution level.
Our partnership agreement provides that we may issue an unlimited number of limited partner interests without the consent of our unitholders. Such units may be issued on the terms and conditions established in the sole discretion of our general partner. Any issuance of additional units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the market price of, units outstanding prior to such issuance. The payment of distributions on these additional units could increase the risk that we would be unable to maintain or increase our anticipated initial quarterly distribution. Please read “Description of Our Partnership Agreement—Issuance of Additional Securities.”
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.
Sales by any of our existing unitholders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our common unit price in the future. Please read “Units Eligible for Future Sale.”
Control of our general partner and the limited partnership that indirectly holds the other 50% of the incentive distribution rights in ETP may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner, to sell or transfer all or part of their ownership interest in our general partner to a third party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by the board of directors and officers.
In addition, the owners of our general partner control the limited partnership that indirectly holds the other 50% of the incentive distribution rights in ETP. This limited partnership can likewise be transferred to a third party without unitholder consent.
Our general partner only has one executive officer, and we are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative, legal and other services necessary to operate our business.
John W. McReynolds, the President and Chief Financial Officer of our general partner, is the only executive officer charged with managing our business. We rely on ETP to provide all of the financial, accounting, administrative, legal and other services needed to operate our business. These services are provided pursuant to the terms of a shared services agreement, and we cannot assure you that these services will continue to be made available to us on terms that are reasonable or at all. In the event that Mr. McReynolds retires, dies or becomes disabled or ceases to serve as the President and Chief Financial Officer of our general partner for any reason, his duties would be provided under the shared services agreement until one or more new executive officers are selected by the board of directors of our general partner.
Moreover, we depend on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Ray C. Davis and Kelcy L. Warren, the founders of its midstream business, as well as other key members of ETP’s management team such as H. Michael Krimbill, R.C. Mills and Mackie McCrea. Messrs. Davis and Warren have been integral to the success of ETP’s midstream, transportation and storage
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business because of their ability to identify and develop strategic business opportunities. Losing their leadership could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
ETP’s executive officers that provide services to us pursuant to the shared services agreement will be allocating their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under limited circumstances.
As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions. Please read “Description of Our Partnership Agreement—Limited Liability.”
Under limited circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, neither Energy Transfer Equity nor ETP may make a distribution to its unitholders if the distribution would cause Energy Transfer Equity’s or ETP’s respective liabilities to exceed the fair value of their respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
If in the future we cease to manage and control ETP, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control ETP and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.
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Our common unit price may be volatile, and a trading market that will provide you with adequate liquidity may not develop.
Prior to this offering there has been no public market for our common units. An active market for our common units may not develop or may not be sustained after this offering. The initial public offering price of our common units will be determined by negotiations between us and the underwriters, based on several factors that we discuss in the “Underwriting” section of this prospectus. This price may not be indicative of the market price for our common units after this initial public offering. The market price of our common units could be subject to significant fluctuations after this offering, and may decline below the initial public offering price. You may be unable to resell your common units at or above the initial public offering price. The following factors could affect our unit price:
| • | ETP’s operating and financial performance and prospects; |
| • | quarterly variations in the rate of growth of our financial indicators, such as distributable cash flow per unit, net income and revenues; |
| • | changes in revenue or earnings estimates or publication of research reports by analysts; |
| • | speculation by the press or investment community; |
| • | sales of our common units by our unitholders; |
| • | actions by our existing unitholders prior to their disposition of our common units; |
| • | announcements by ETP or its competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments; |
| • | general market conditions; and |
| • | domestic and international economic, legal and regulatory factors related to ETP’s performance. |
The equity markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common units. In addition, potential investors may be deterred from investing in our common units for various reasons, including the very limited number of publicly traded entities whose assets consist almost exclusively of partnership interests in a publicly traded partnership. The lack of liquidity may also contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
We will incur increased costs as a result of being a public company, including costs related to compliance with Section 404 of Sarbanes-Oxley.
Prior to this offering, we have been a private company and have not filed reports with the Commission. Following this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. Although we produce our financial statements in accordance with the requirements of generally accepted accounting principles, our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. For example, as we prepare to become subject to the requirements of Section 404 of Sarbanes-Oxley for the fiscal year ended August 31, 2006, our auditors may identify deficiencies in the operational effectiveness of our internal controls and procedures and may advise us that these deficiencies could collectively constitute a significant deficiency that may rise to the level of a reportable condition under Section 404. Similarly, when ETP becomes subject to Section 404 upon the filing of its annual report on Form 10-K for the year ended August 31, 2005, its auditors may identify significant deficiencies in its internal controls and procedures.
In order to comply with the requirements of Section 404 of Sarbanes-Oxley, both we and ETP will need to hire additional accounting and finance staff and implement new financial systems and procedures. We cannot assure you that we or ETP will be able to hire additional staff or implement appropriate procedures on a timely
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basis. Failure to hire such staff and implement such procedures could have an adverse effect on our ability or the ability of ETP to satisfy applicable obligations under the Exchange Act and Sarbanes-Oxley. In addition, the amount of cash distributions from ETP that will be available for distribution to our unitholders will be reduced by the costs associated with our becoming a public company.
Our partnership agreement restricts the rights of unitholders owning 20% or more of our units.
Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Risks Related to Energy Transfer Partners’ Business
Because our cash flow will initially consist exclusively of distributions from ETP, risks to ETP’s business are also risks to us. We have set forth below many of the risks to ETP’s business or results of operations, the occurrence of which could negatively impact ETP’s financial performance and decrease the amount of cash it is able to distribute to us, thereby impacting the amount of cash that is available for distribution to our unitholders.
The profitability of ETP’s midstream, transportation and storage business is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which factors are beyond ETP’s control and have been volatile.
Income from ETP’s midstream, transportation and storage business is exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the Southeast Texas System, ETP purchases natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gathers and delivers the natural gas to pipelines where ETP typically resells the natural gas at the index price. Generally, the gross margins that ETP realizes under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Accordingly, an increase in the price of natural gas relative to the price of NGLs could have a material adverse effect on ETP’s results of operations.
For a portion of the natural gas gathered at the Southeast Texas System, ETP enters into percentage-of-proceeds arrangements and keep-whole arrangements pursuant to which ETP agrees to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remits to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed-upon percentage of the residue gas and NGL volumes to the producer and sells the volumes it keeps to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on ETP’s results of operations. Under keep-whole arrangements, ETP generally sells the NGLs produced from its gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, ETP’s revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if it is not able to bypass its processing plants and sell the unprocessed natural gas.
In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during ETP’s fiscal year ended August 31, 2004, the New York Mercantile Exchange
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(“NYMEX”) settlement price for the prior month contract ranged from a high of $6.68 per MMBtu to a low of $4.43 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during its fiscal year ended August 31, 2004 ranged from a high of approximately $0.79 per gallon to a low of approximately $0.48 per gallon.
Average realized natural gas sales prices for ETP’s fiscal year ended August 31, 2004 exceeded its historical realized natural gas prices. For example, ETP’s average realized natural gas price increased $0.14, or 2.8%, from $4.99 per MMBtu for the 11 months ended August 31, 2003 to $5.13 per MMBtu for its fiscal year ended August 31, 2004. On August 31, 2005, the NYMEX settlement price for October natural gas deliveries was $11.47 per MMBtu, which was 122% higher than ETP’s average natural gas price for its fiscal year ended August 31, 2004. Natural gas prices are subject to significant fluctuations, and we cannot assure you that natural gas prices will remain at the high levels recently experienced.
ETP’s Oasis Pipeline, East Texas Pipeline System, ET Fuel System and Houston Pipeline System receive fees for transporting natural gas for ETP’s customers. Although a significant amount of the pipeline capacity of the East Texas Pipeline and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of ETP’s transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels.
The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:
| • | the impact of weather on the demand for oil and natural gas; |
| • | the level of domestic oil and natural gas production; |
| • | the availability of imported oil and natural gas; |
| • | actions taken by foreign oil and gas producing nations; |
| • | the availability of local, intrastate and interstate transportation systems; |
| • | the price, availability and marketing of competitive fuels; |
| • | the demand for electricity; |
| • | the impact of energy conservation efforts; and |
| • | the extent of governmental regulation and taxation. |
ETP’s success depends upon its ability to continually contract for new sources of natural gas supply.
In order to maintain or increase throughput levels on its gathering and transportation pipeline systems and asset utilization rates at its treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services. ETP may be unable to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and it may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting ETP’s ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near its gathering systems or in areas that provide access to its transportation pipelines or markets to which its systems connect. The primary factors affecting ETP’s ability to attract customers to its transportation pipelines, including the Oasis Pipeline, the East Texas Pipeline System, the ET Fuel System or the Houston Pipeline System, consist
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of ETP’s access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity and production generally decrease as oil and natural gas prices decrease. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, ETP has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.
A substantial portion of ETP’s assets, including its gathering systems and its processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. In particular, the Southeast Texas System covers portions of the Austin Chalk, Buda, Georgetown, Edwards, Wilcox and other producing formations in southeast Texas, which we collectively refer to as the Austin Chalk trend. This natural gas producing region has generally been characterized by high initial flow rates followed by steep initial declines in production. Accordingly, ETP’s cash flows will also decline unless ETP is able to access new supplies of natural gas by connecting additional production to these systems.
ETP’s transportation pipelines are also dependent upon natural gas production in areas served by its pipelines or in areas served by other gathering systems or transportation pipelines that connect with its transportation pipelines. A material decrease in natural gas production in ETP’s areas of operation or in other areas that are connected to its areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas it handles, which would reduce ETP’s revenues and operating income. In addition, ETP’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in its currently connected supplies.
The volumes of natural gas ETP transports on its pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel Hub, the four major natural gas trading hubs served by its pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those operated by ETP.
ETP may be unable to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for qualified assets.
ETP’s strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage, propane and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance ETP’s ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. ETP regularly considers and enters into discussions regarding, and is currently contemplating, the acquisition of additional assets and businesses, stand-alone development projects and other transactions that it believes will present opportunities to realize synergies and increase its cash flow.
ETP may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on its access to capital will impair its ability to execute this strategy. Expensive capital will limit ETP’s ability to develop or acquire accretive assets. It may be unable to raise the necessary funds on satisfactory terms, if at all.
Consistent with ETP’s acquisition strategy, ETP is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve
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ETP’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure you that ETP’s current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to ETP.
In addition, ETP is experiencing increased competition for the assets it purchases or contemplates purchasing. Increased competition for a limited pool of assets could result in ETP losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit ETP’s ability to fully execute its growth strategy. ETP’s inability to execute its growth strategy may materially adversely impact the market price of our securities.
If ETP does not make acquisitions on economically acceptable terms, its future growth could be limited.
Historically, ETP’s results of operations, and its ability to grow and to increase distributions to unitholders, including us, has depended principally on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit. ETP’s acquisition strategy is based, in part, on its expectation of ongoing divestitures of pipeline assets by large industry participants. A material decrease in such divestitures would limit ETP’s opportunities for future acquisitions and could adversely affect its business, results of operations, financial condition and cash flows available for distribution to its unitholders, including us.
In addition, ETP may be unable to make accretive acquisitions for any of the following reasons, among others:
| • | because it is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; |
| • | because it is unable to raise financing for such acquisitions on economically acceptable terms; |
| • | because it is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does; or |
| • | because a proposed acquisition is prohibited by applicable antitrust, anti-takeover or other regulations in the United States. |
Furthermore, even if ETP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in no increase or even a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP may:
| • | fail to successfully integrate and realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements; |
| • | decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions; |
| • | significantly increase its interest expense or financial leverage if it incurs additional debt to finance acquisitions; |
| • | encounter difficulties operating in new geographic areas or new lines of business; |
| • | incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which it is not indemnified or for which the indemnity is inadequate; |
| • | be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets; |
| • | less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or |
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| • | incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges. |
If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that it will consider.
ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System, and the loss of any of these key producers could adversely affect its financial results.
For the fiscal year ended August 31, 2004, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied ETP with approximately 41% of the Southeast Texas System’s natural gas supply. ETP is not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply to ETP, ETP would be adversely affected unless it were able to acquire comparable supplies of natural gas from other producers.
ETP depends on key customers to transport natural gas on its East Texas Pipeline and ET Fuel System.
ETP has entered into a nine- and ten-year, fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on ETP’s pipelines. ETP has also entered into an eight-year, fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which we refer to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. ETP has also entered into two eight-year natural gas storage contracts with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on ETP’s cash flow and results of operations if it were not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
Federal, state or local regulatory measures could adversely affect ETP’s business.
As a natural gas gatherer and intrastate pipeline company, ETP is generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects ETP’s business and the market for its products. In recent years, FERC has pursued pro-competitive policies in the regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities.
The rates, terms and conditions of some of the transportation and storage services ETP provides on the Oasis Pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable, amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC approval. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.
ETP’s intrastate natural gas transportation and storage facilities are subject to state regulation in Texas and Louisiana, the states in which it operates these types of pipelines. ETP’s intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for
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transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business may be adversely affected.
ETP’s pipeline operations are also subject to ratable take and common purchaser statutes in Texas and Louisiana, the states where it operates. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP operates that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s business.
ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the ET Fuel System and the Houston Pipeline System natural gas storage facilities are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRRC-jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. The TRRC’s regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.
The states in which ETP conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing and operating their pipelines, and subjects pipelines to regular inspections. Some of ETP’s gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.
Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws could result in the imposition of administrative, civil and criminal remedies.
ETP’s business involves hazardous substances and may be adversely affected by environmental regulation.
ETP’s natural gas midstream, transportation and storage, as well as its propane, businesses are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for ETP’s operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from ETP’s pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from ETP’s operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.
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ETP may incur substantial environmental costs and liabilities because the underlying risk are inherent to its operations. Joint and several, strict liability may be incurred under environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons or wastes on, under, or from ETP’s properties and facilities, many of which have been used for industrial activities for a number of years. Private parties, including the owners of properties through which ETP’s gathering systems pass or facilities where ETP’s petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on our operations or financial position.
Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect its revenues and cash flow.
Users of ETP’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures or other causes could result in reduced volumes being transported in ETP’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s pipelines. Any reduction in volumes transported in its pipelines would adversely affect its revenues and cash flow.
ETP encounters competition from other midstream, transportation and storage companies and propane companies.
ETP experiences competition in all of its markets. Its principal areas of competition include obtaining natural gas supplies for the Southeast Texas System and natural gas transportation customers for the Oasis Pipeline, the East Texas Pipeline and the ET Fuel System. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems owned by Duke Energy Field Services, LLC. The East Texas Pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale area of the Fort Worth Basin in north Texas. The ET Fuel System competes with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub and the Fort Worth Basin Pipeline competes with other natural gas transportation pipelines serving the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that ETP competes with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners L.P., and Enbridge, Inc. Many of ETP’s competitors have greater financial resources and access to larger natural gas supplies than it does.
The acquisition of the Houston Pipeline System, which will increase the number of interstate pipelines and natural gas markets to which ETP has access, will also expand its principal areas of competition to areas such as southeast Texas and the Texas Gulf Coast. As a result of ETP’s expanded market presence and diversification, it will face additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas, that have greater financial resources and access to larger natural gas supplies than it does.
ETP’s propane business competes with a number of large national and regional propane companies, and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, it is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further
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intensifies competition. Most of ETP’s propane retail branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:
| • | price; |
| • | reliability and quality of service; |
| • | responsiveness to customer needs; |
| • | safety concerns; |
| • | long-standing customer relationships; |
| • | the inconvenience of switching tanks and suppliers; and |
| • | the lack of growth in the industry. |
Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks.
One of the ways that ETP expects to grow its business is through the construction of additions to its existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities, or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond its control and require the expenditure of significant amounts of capital that it will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, ETP’s revenues may not increase immediately following the completion of particular projects. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. Moreover, ETP may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput to achieve its expected investment return, which could adversely affect its results of operations and financial condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.
ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its unitholders, including us.
The risks of nonpayment and nonperformance by ETP’s customers is a major concern in its business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP is subject to risks of loss resulting from nonpayment or nonperformance by its customers. Any increase in the nonpayment and nonperformance by its customers could reduce ETP’s ability to make distributions to its unitholders, including us.
ETP may be unable to bypass the La Grange processing plant, which could expose it to the risk of unfavorable processing margins.
Because of ETP’s ownership of the Oasis Pipeline, it can generally elect to bypass the La Grange processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the Southeast Texas System with lean gas transported on the Oasis Pipeline. In some circumstances, such as when ETP does not have a sufficient amount of lean gas to blend with the volume of rich gas that it receives at the La Grange processing plant, it may have to process the rich gas. If ETP has to process when processing margins are unfavorable, its results of operations will be adversely affected.
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ETP may be unable to retain existing customers or secure new customers, which would reduce its revenues and limit its future profitability.
The renewal or replacement of existing contracts with ETP’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets it serves.
For its fiscal year ended August 31, 2004, approximately 12% of ETP’s sales of natural gas were to industrial end-users and utilities. For the year ended December 31, 2004, approximately 36% of the Houston Pipeline System’s sales were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP in the marketing of natural gas, ETP often competes in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on its profitability.
ETP’s storage business depends on neighboring pipelines to transport natural gas.
To obtain natural gas, ETP’s storage business depends on the pipelines to which it has access. Many of these pipelines are owned by parties not affiliated with ETP. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on its storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on its storage revenues.
ETP’s pipeline integrity program may cause it to incur significant costs and liabilities.
In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of ETP’s current pipeline integrity testing programs, it estimates that compliance with this final rule for its existing transportation assets will result in capital costs of $4.5 million during the period between 2005 to 2010, as well as operating and maintenance costs of $1.8 million during that five-year period. ETP is continuing to assess the impact of this final rule on the ET Fuel System and the Houston Pipeline System and cannot predict any estimated compliance costs for those assets at this time. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.
Because weather conditions may adversely affect demand for propane, the volumes of propane sold by and the results of operations of ETP’s propane business are vulnerable to warm winters.
Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of ETP’s customers rely heavily on propane as a heating fuel. Typically, ETP sells approximately two-thirds of its retail propane volume during the peak heating season of October through March. ETP’s propane business can be adversely affected by warmer winter weather which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect ETP’s operating and financial results, its access
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to capital and its acquisition activities may be limited. Variations in weather in one or more of the regions where ETP operates can significantly affect the total volume of propane that it sells and the profits realized on these sales. Agricultural demand for propane is also affected by weather during the harvest season as poor harvests or dry weather reduce demand for propane used in crop drying.
Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect the profit margins of ETP’s propane business.
The propane industry is a margin-based business in which gross profits depend on the excess of sales prices over supply costs. As a result, the profitability of ETP’s propane business is sensitive to changes in energy prices and, in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, ETP may be unable to pass on these increases to its customers through retail or wholesale prices. Propane is a commodity, and the price that ETP pays for propane can fluctuate significantly in response to changes in supply or other market conditions over which ETP has no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce the gross profits from ETP’s propane business and could, if continued over an extended period of time, reduce demand by encouraging ETP’s retail customers to conserve or convert to alternative energy sources.
ETP’s results of operations and its ability to make distributions or pay interest or principal on debt securities could be negatively impacted by price and inventory risk related to its propane business and management of these risks.
ETP generally attempts to minimize its cost and inventory risk related to its propane business by purchasing propane on a short-term basis, under supply contracts that typically have a one-year term and at a cost that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure that adequate supply sources are available during periods of high demand, ETP may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in its facilities, at major storage facilities owned by third parties or for future delivery. This strategy may not be effective in limiting ETP’s cost and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the cost at which ETP made such purchases, it could adversely affect ETP’s profits.
Some of ETP’s propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to its anticipated sales volumes under the commitments, ETP may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. ETP enters into such contracts and exercises such options at volume levels that it believes are necessary to manage these commitments. The risk management of ETP’s inventory and contracts for the future purchase of product could impair its profitability if its customers do not fulfill their obligations.
ETP also engages in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on estimates by ETP’s management of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of ETP’s control occur, such activities could generate a loss in future periods and potentially impair ETP’s profitability.
ETP’s propane business depends on its principal propane suppliers, which increases the risk of an interruption in supply.
During fiscal 2004, ETP purchased approximately 24.9% of its propane from Enterprise Products Operating L.P., approximately 18.8% of its propane from Dynegy Liquids Marketing and Trade and approximately 19% of its propane from M-P Energy Partnership, the Canadian partnership in which ETP owns a 60% interest. If
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supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.
Historically, a substantial portion of the propane that ETP purchases has originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to ETP through major common carrier pipelines. Any significant interruption in the service at Mt. Belvieu or other major market points, or on the common carrier pipelines used by ETP, would adversely affect its ability to obtain propane.
Competition from alternative energy sources may cause ETP to lose propane customers, thereby reducing its revenues.
Competition in ETP’s propane business from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause ETP to lose customers, thereby reducing its revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect ETP’s operations.
Energy efficiency and technological advances may affect the demand for propane and adversely affect ETP’s operating results.
The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect ETP’s operations.
Risks Related to Conflicts of Interest
Conflicts of interest exist and may arise in the future among us, ETP and our respective general partners and affiliates. Future conflicts of interest may arise among us and the entities affiliated with any general partner interests we acquire or among ETP and such entities. For a further discussion of conflicts of interest that may arise, please read “Conflicts of Interest and Fiduciary Duties” and “Certain Relationships and Related Party Transactions—Shared Services Agreement.”
Although we control ETP through our ownership of its general partner, ETP’s general partner owes fiduciary duties to ETP and ETP’s unitholders, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including ETP’s general partner, on the one hand, and ETP and its limited partners, on the other hand. The directors and officers of ETP’s general partner have fiduciary duties to manage ETP in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage ETP in a manner beneficial to ETP and its limited partners. The board of directors of ETP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
For example, conflicts of interest may arise in the following situations:
| • | the allocation of shared overhead expenses to ETP and us; |
| • | the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand; |
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| • | the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business; |
| • | the determination whether to make borrowings under ETP’s revolving working capital facility to pay distributions to ETP’s partners; and |
| • | any decision we make in the future to engage in business activities independent of ETP. |
The fiduciary duties of our general partner’s officers and directors may conflict with those of ETP’s general partner.
Conflicts of interest may arise because of the relationships between ETP’s general partner, ETP and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner’s directors are also directors and officers of ETP’s general partner, and have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and ETP’s unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
Our general partner’s affiliates, including the partnership that indirectly holds the other 50% of ETP’s incentive distribution rights, may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Conflicts of Interest and Fiduciary Duties” and “Certain Relationships and Related Party Transactions.”
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.
Following this offering, conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:
| • | Our general partner is allowed to take into account the interests of parties other than us, including ETP and its affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders. |
| • | Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
| • | Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders. |
| • | Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us. |
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| • | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. |
| • | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”
Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
| • | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; |
| • | provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests; |
| • | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and |
| • | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. |
In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, affiliates of our general partner will own approximately 86.6% of our common units on a fully diluted basis. Please read “Description of Our Partnership Agreement—Limited Call Right.”
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ETP may issue additional ETP units, which may increase the risk that ETP will not have sufficient available cash to maintain or increase its per unit distribution level.
ETP has wide latitude to issue additional units on terms and conditions established by its general partner. The payment of distributions on those additional units may increase the risk that ETP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders.
The issuance of additional common units or other equity securities of equal rank will have the following effects:
| • | our unitholders’ proportionate ownership interest in ETP will decrease; |
| • | the amount of cash available for distribution on each common unit may decrease; and |
| • | the market price of our common units may decline. |
Furthermore, our partnership agreement does not give our unitholders the right to approve our issuance of equity securities.
Tax Risks to Our Common Unitholders
You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.
If we or ETP were to become subject to entity-level taxation for federal or state tax purposes, then our cash available for distribution to you would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of our units.
If ETP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.
Current law may change, causing us or ETP to be treated as a corporation for federal income tax purposes or otherwise subjecting us or ETP to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or ETP as an entity, the cash available for distribution to you would be reduced.
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A successful IRS contest of the federal income tax positions we or ETP takes may adversely impact the market for our common units or ETP common units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions that we or ETP take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or ETP take. A court may not agree with some or all of the positions we or ETP take. Any contest with the IRS may materially and adversely impact the market for our common units or ETP’s common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by ETP and therefore indirectly by us, as a unitholder and as the owner of the general partner of ETP. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.
Tax gain or loss on the disposition of our units could be different than expected.
If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. However, this legislation is only effective for taxable years of regulated investment companies beginning after October 22, 2004. For taxable years of regulated investment companies beginning on or before October 22, 2004, very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of units and could have a negative impact on the value
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of our units or result in audit adjustments to your tax returns. Please read “Material Tax Consequences—Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.
You will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ETP do business or own property. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We or ETP may own property or conduct business in other states or foreign countries in the future. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our units.
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We expect to receive net proceeds of approximately $266.3 million from the sale of the 15,000,000 common units we are offering, after deducting underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters exercise their over-allotment option in full, we expect to receive additional net proceeds of approximately $40.3 million, which we would use to fund the redemption of 2,250,000 common units from our current equity owners. We base these amounts on an assumed initial public offering price of $19.00 per common unit, the mid-point of the range set forth on the cover page of this prospectus.
We will use the net proceeds from this offering to repay approximately $240 million of indebtedness outstanding under our $600 million senior secured term loan facility. This term loan facility matures on June 16, 2008 and bears interest at an initial rate of LIBOR plus 3%. This initial interest rate is subject to adjustment based upon our ratio of total debt to EBITDA, which adjustment is expected to decrease the applicable rate to LIBOR plus 2.25% by the time of the closing of this offering. The amounts borrowed under our senior secured term loan facility were distributed to our equity owners.
We will use the remaining net proceeds, together with an aggregate cash capital contribution of $119.7 million from our equity owners prior to the closing of this offering, to fund a portion of our acquisition of an additional 3.64 million common units of ETP.
If the underwriters exercise all or any portion of their over-allotment option, we will use all of the net proceeds from the sale of our common units sold pursuant to the exercise of that option to fund the redemption of an equal number of common units from our current equity owners.
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The following table sets forth our cash and cash equivalents and our capitalization as of May 31, 2005:
| • | on a consolidated historical basis for Energy Transfer Equity; |
| • | on a pro forma basis to give effect to the borrowing of $600 million by us under our senior secured term loan facility and a $119.7 million capital contribution from our existing owners; and |
| • | as further adjusted to reflect the sale of 15,000,000 of our common units in this offering and the application of the net proceeds as described under “Use of Proceeds.” |
The historical financial data of Energy Transfer Equity presented in the table below is derived from and should be read in conjunction with Energy Transfer Equity’s historical financial statements, including the accompanying notes, included elsewhere in this prospectus. Please read our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus for a complete description of the adjustments we have made to arrive at our pro forma and pro forma as adjusted capitalization data.
| As of May 31, 2005 | ||||||||||
| Historical |
Pro Forma |
Pro Forma As Adjusted | ||||||||
| (Dollars in thousands) | ||||||||||
| Cash and cash equivalents |
$ | 21,607 | $ | 246,339 | $ | 267,946 | ||||
| Long-term borrowings, including current portion: |
||||||||||
| ETP senior notes |
747,797 | 747,797 | ||||||||
| ETP swing-line loans |
30,000 | 30,000 | ||||||||
| ETP revolving credit facility |
443,000 | (60,000 | ) | 383,000 | ||||||
| HOLP senior secured notes |
317,143 | 317,143 | ||||||||
| HOLP senior revolving acquisition facility |
41,000 | 41,000 | ||||||||
| HOLP long-term portion of senior revolving working capital facility |
6,493 | 6,493 | ||||||||
| HOLP non-competes and other |
18,147 | 18,147 | ||||||||
| ETE term loan facility |
— | 360,000 | 360,000 | |||||||
| Total principal amount of debt obligations |
1,603,580 | 300,000 | 1,903,580 | |||||||
| Minority interest |
1,257,862 | 106,570 | 1,364,432 | |||||||
| Partners’ equity of Energy Transfer Equity: |
||||||||||
| Limited partners |
413,464 | (149,283 | ) | 264,181 | ||||||
| General partner |
4,550 | (4,248 | ) | 302 | ||||||
| Accumulated other comprehensive income |
5,961 | — | 5,961 | |||||||
| Total equity |
423,975 | (153,531 | ) | 270,444 | ||||||
| Total capitalization |
$ | 3,285,417 | $ | 253,039 | $ | 3,538,456 | ||||
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Dilution is the amount by which the offering price paid by purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Based on the initial public offering price of $19.00 per common unit, the mid-point of the range set forth on the cover page of this prospectus, on a pro forma as adjusted basis as of May 31, 2005, after giving effect to this offering of 15,000,000 common units, the capital contribution of $119.7 million to be made by our existing equity owners, the purchase of 3.64 million ETP common units, our net tangible book value was $(197.0) million, or $(1.69) per common unit, assuming the full exercise by the underwriters of their over-allotment option. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.
| Assumed initial public offering price per common unit |
$ | 19.00 | ||||||
| Pro forma net tangible book value per common unit before this offering |
$ | (5.79 | ) | |||||
| Increase in net tangible book value per common unit attributable to new investors |
4.10 | |||||||
| Less: Pro forma net tangible book value per common unit after this offering |
(1.69 | ) | ||||||
| Immediate dilution in net tangible book value per common unit to new investors |
$ | 20.69 | ||||||
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our current owners and their affiliates in respect of their common units and by the purchasers of units in this offering upon consummation of the transactions contemplated by this prospectus.
| Units Acquired |
Total Consideration |
Average Paid Per Unit | |||||||||||||
| Number |
Percent |
Number |
Percent |
||||||||||||
| (in millions) | |||||||||||||||
| Current owners |
100,560,000 | (1) | 86.6 | % | $ | % | $ | ||||||||
| New investors |
15,000,000 | 12.9 | % | $ | |||||||||||
| General partner units |
634,000 | 0.5 | % | $ | |||||||||||
| Total |
116,194,000 | 100.0 | % | $ | 100 | % | $ | ||||||||
| (1) | Includes Class B units that are convertible into common units on a one-for-one basis at the election of the holders. |
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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read footnote (a) to the table entitled “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and material risks inherent in our and ETP’s business. Unless otherwise stated, the information presented in this section assumes that the underwriters will exercise their option to purchase additional units in full.
For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements for the years ended August 31, 2004, 2003 and 2002, our historical financial statements for the nine months ended May 31, 2005 and 2004, and our unaudited pro forma condensed consolidated financial statements for the year ended August 31, 2004 and nine months ended May 31, 2005, included elsewhere in this prospectus.
Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than retaining it. It is important that you understand that our only cash-generating assets currently consist of partnership interests, including incentive distribution rights, in ETP from which we receive quarterly distributions. We currently have no independent operations outside of our interests in ETP. Because we believe we will have relatively low cash requirements for operating expenses and that we will finance any material capital investments from external financing sources, we believe that our investors are best served by distributing all of our available cash as described below. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to you than would be the case were we subject to tax. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.
Restrictions on Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time. These restrictions include the following:
| • | Our distribution policy is subject to restrictions on distributions under our current term loan agreement. Specifically, our current term loan agreement contains material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Debt Obligations—Energy Transfer Equity.” Should we be unable to comply with the restrictions under our term loan agreement, we would be prohibited from making cash distributions to you notwithstanding our stated distribution policy. |
| • | ETP’s distribution policy is subject to restrictions on distributions under its credit agreements. Specifically, ETP’s credit agreements contain material financial tests and covenants that it must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Debt Obligations—Energy Transfer Partners.” Should ETP be unable to comply with the restrictions under its credit agreements, ETP would be prohibited from making cash distributions to us, which in turn would prevent us from making cash distributions to you notwithstanding our stated distribution policy. |
| • | Our board of directors has broad discretion to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. |
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| • | The board of directors of ETP’s general partner has broad discretion to establish reserves for the prudent conduct of ETP’s business and for future cash distributions to ETP’s unitholders, and the establishment of those reserves could result in a reduction in cash distributions that we would otherwise anticipate receiving from ETP, which in turn could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. |
| • | While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including our cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units. Following completion of this offering, our current owners will own approximately 86.6% of our outstanding common (including outstanding Class B units that are convertible into common units on a one-for-one basis at the election of the holder) and will have the ability to amend our partnership agreement. Some of these owners are officers and directors of the general partner of ETP. |
| • | Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our cash distribution policy and the decision to make any distribution is at the discretion of our general partner, taking into consideration the terms of our partnership agreement. |
| • | The amount of distributions paid under ETP’s cash distribution policy and the decision to make any distribution to its unitholders are at the discretion of ETP’s general partner, taking into consideration the terms of its partnership agreement. |
| • | Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. |
| • | We may lack sufficient cash to pay distributions to our unitholders due to increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs of us or ETP and its subsidiaries. |
Our Cash Distribution Policy Limits Our Ability to Grow. As with most other master limited partnerships, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, since our only cash-generating assets currently consists of our partnership interests in ETP, including incentive distribution rights, our growth initially will be dependent upon ETP’s ability to increase its quarterly distribution per unit. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.
ETP’s Ability to Grow is Dependent on its Ability to Access External Growth Capital. Consistent with the terms of its partnership agreement, ETP has distributed to its partners most of the cash generated by its operations. As a result, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund its acquisition and growth capital expenditures. Accordingly, to the extent ETP is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent ETP issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that ETP will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or other debt to finance its growth strategy would result in increased interest expense to ETP, which in turn may impact the available cash that we have to distribute to our unitholders.
Our Cash Distribution Policy. Upon the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial distribution of $0.175 per unit per complete quarter, or $0.70 per unit per year, to be paid no later than 50 days after the end of each fiscal quarter.
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This equates to an aggregate cash distribution of approximately $20.3 million per quarter, or $81.3 million per year, based on the common units and Class B units outstanding immediately after completion of this offering, including the common units issuable upon exercise of the underwriters’ option to purchase additional common units.
The table below sets forth the assumed number of outstanding common units (including the number of outstanding Class B units that are convertible into common units on a one-for-one basis) upon the closing of this offering, assuming the full exercise of the underwriters’ option to purchase additional common units, the redemption of 2,250,000 common units from our existing equity owners, and the aggregate distribution amounts payable on our outstanding common units and the general partner units during the year following the closing of this offering at our initial distribution rate of $0.175 per common unit per quarter ($0.70 per common unit on an annualized basis).
| Number of Units |
Distributions | |||||||
| One Quarter |
Four Quarters | |||||||
| Publicly held common units |
17,250,000 | $ | 3,018,750 | $ | 12,075,000 | |||
| Common units held by our current owners (1) |
98,310,061 | 17,204,261 | 68,817,043 | |||||
| General Partner units |
634,000 | 111,000 | 443,800 | |||||
| Total |
116,194,061 | $ | 20,334,000 | $ | 81,335,843 | |||
| (1) | Includes the number of outstanding Class B units that are convertible into common units on a one-for-one basis at the election of the holders. Each Class B unit is entitled to receive the same cash distribution per quarter as each common unit. |
These distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter at the anticipated initial distribution rate, our unitholders will not be entitled to receive such payments in the future. We will pay our distributions within 50 days after the end of each quarter ending February, May, August and November to holders of record. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.
Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.
ETP’s Cash Distribution Policy. Like us, ETP has adopted a cash distribution policy that requires it to distribute its available cash to its unitholders on a quarterly basis. Under ETP’s partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from ETP’s business in excess of the amount its general partner determines is necessary or appropriate to provide for the conduct of its business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. ETP’s determination of available cash takes into account the desire to establish cash reserves in some quarterly periods that it may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if its business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. ETP’s determination of available cash also allows it to maintain reserves to provide funding for its growth opportunities. ETP makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of several significant acquisitions and internal growth projects that have been funded through external financing sources.
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The following table sets forth, for the periods indicated, the amount, record date and payment date of the quarterly cash distributions ETP paid per each ETP common unit with respect to the quarter indicated. All distributions paid by ETP to date have consisted of available cash from operating surplus of ETP under ETP’s partnership agreement. The actual cash distributions of ETP (i.e., payments to the partners of ETP) occur within 45 days after the end of such quarter. ETP and its predecessor have had an established historical record of paying quarterly cash distributions to their partners.
| Cash Distribution History | |||||||
| Per Unit |
Record Date |
Payment Date | |||||
| 2003 | |||||||
| 1st Quarter |
$ | 0.31875 | December 30, 2002 | January 14, 2003 | |||
| 2nd Quarter |
0.31875 | April 4, 2003 | April 14, 2003 | ||||
| 3rd Quarter |
0.31875 | July 7, 2003 | July 15, 2003 | ||||
| 4th Quarter |
0.32500 | October 8, 2003 | October 15,2003 | ||||
| 2004 | |||||||
| 1st Quarter |
$ | 0.32500 | December 30, 2003 | January 14, 2004 | |||
| 2nd Quarter |
0.35000 | April 2, 2004 | April 14, 2004 | ||||
| 3rd Quarter |
0.37500 | July 2, 2004 | July 15, 2004 | ||||
| 4th Quarter |
0.41250 | October 7, 2004 | October 15, 2004 | ||||
| 2005 | |||||||
| 1st Quarter |
$ | 0.43750 | January 5, 2005 | January 14, 2005 | |||
| 2nd Quarter |
0.46250 | April 6, 2005 | April 14, 2005 | ||||
| 3rd Quarter |
0.48750 | July 8, 2005 | July 15, 2005 | ||||
| 4th Quarter |
0.5000 | September 30, 2005 | October 14, 2005 | ||||
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.175 per common unit per quarter. In those sections, we present two tables, including:
| • | “Unaudited Pro Forma Consolidated Available Cash,” in which we present the amount of available cash we would have had for our fiscal year ended August 31, 2004, giving pro forma effect to: |
| • | the business combination in January 2004 with Heritage Propane Partners; |
| • | the acquisition in June 2004 by ETP of the midstream natural gas assets of TXU Fuel Company, a gas transportation subsidiary of TXU Corp., which included approximately 2,000 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities, fractionation facilities and a natural gas processing plant and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | the issuance by ETP of $750.0 million of 5.95% senior notes on January 18, 2005 and the application of the net proceeds from that issuance to repay outstanding indebtedness under ETP’s secured credit facilities; |
| • | the acquisition in January 2005 by ETP of the controlling interests in the companies that own the Houston Pipeline System, consisting of approximately 4,200 miles of intrastate natural gas pipelines and related storage and transportation facilities located in Texas and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | our new term loan in the aggregate principal amount of $600.0 million, the payment of related expenses and the distribution of the net proceeds of such borrowings to our unitholders in June 2005; |
| • | the issuance by ETP of $400.0 million of 5.65% senior notes on July 29, 2005 and the application of net proceeds from that issuance to repay outstanding indebtedness under ETP’s revolving credit facility, to fund ETP’s recently announced capital expansion projects and for general partnership purposes; |
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| • | a $119.7 million equity contribution from our existing partners; |
| • | the current ETP cash distributions of $0.50 per unit per quarter (or $2.00 per unit on an annualized basis); and |
| • | this offering and the application of the net proceeds as described under “Use of Proceeds.” |
| • | “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA,” in which we present the operating assumptions for the four fiscal quarters ending August 31, 2006, which we believe will enable us to fully fund our intended distribution. |
Our tables entitled “Unaudited Pro Forma Consolidated Available Cash” and “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA” used in this section as described below have been prepared by, and are the responsibility of, our management. Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information. Such independent registered public accounting firms’ reports included elsewhere in this prospectus relate to the appropriately described historical financial information contained in this section. Such reports do not extend to the tables and related information contained in this section and should not be read to do so. In addition, such tables and information were not prepared:
| • | with a view toward compliance with published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information; |
| • | in accordance with accounting principles generally accepted in the United States of America; or |
| • | in accordance with procedures applied under the auditing standards of the Public Company Accounting Oversight Board (United States). |
Our pro forma available cash for fiscal 2004 and for the nine months ended May 31, 2005 would have been more than sufficient to pay the initial quarterly distribution of $0.175 per unit on all units to be outstanding following the completion of this offering.
If we had completed the transactions contemplated in this prospectus on September 1, 2003, pro forma available cash generated during our fiscal year ended August 31, 2004 would have been approximately $92.1 million. This amount would have been more than sufficient to pay the full initial distribution amount of $81.3 million on all our common units, Class B units and general partner units for this year.
If we had completed the transactions contemplated in this prospectus on September 1, 2004, our pro forma available cash for the nine months ended May 31, 2005 would have been approximately $94.4 million. This amount would have been more than sufficient to pay the full initial distribution amount of $61.0 million on all our common units, Class B units and general partner units for this nine-month period.
The following table illustrates, on a pro forma basis, for our fiscal year ended August 31, 2004 and for the nine months ended May 31, 2005, the amount of available cash that would have been available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments. In particular, as reflected in footnote (d) below, you should be aware that “Pro forma acquisition adjustment to Consolidated Adjusted EBITDA” includes adjustments for ETP’s business combination with Heritage on January 20, 2004, ETP’s acquisition of TXU Fuel Company on June 1, 2004 and ETP’s acquisition of 98% of the general partner and limited partner interests of HPL Consolidation LP (“HPL”) on January 26, 2005.
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Unaudited Pro Forma Consolidated Available Cash
| Year Ended August 31, 2004 |
Nine Months Ended May 31, 2005 |
|||||||
| (in thousands) | ||||||||
| Net Cash Provided (Used) by Operating Activities (a) |
$ | 122,098 | $ | 216,859 | ||||
| Plus: |
||||||||
| Cash interest expense |
37,971 | 47,862 | ||||||
| Cash interest income |
— | — | ||||||
| Cash tax expense |
7,227 | 5,586 | ||||||
| Non-cash gain (loss) on sale of property, plant and equipment |
(1,006 | ) | (665 | ) | ||||
| Provision for doubtful accounts |
(1,667 | ) | (4,781 | ) | ||||
| Net changes in working capital accounts, including net changes in price risk management assets and liabilities (b) |
(10,389 | ) | (43,746 | ) | ||||
| Consolidated Adjusted EBITDA (on a cash basis) |
$ | 154,234 | $ | 221,115 | ||||
| Less: Additional expense of being a public company (c) |
(1,695 | ) | (1,309 | ) | ||||
| Plus: Pro forma acquisition adjustment to Consolidated Adjusted EBITDA (d) |
93,261 | 23,375 | ||||||
| Pro forma Consolidated Adjusted EBITDA |
$ | 245,800 | $ | 243,181 | ||||
| Less: |
||||||||
| Pro forma cash interest expense (e) |
(116,463 | ) | (81,143 | ) | ||||
| Pro forma cash tax expense (f) |
(10,915 | ) | (6,194 | ) | ||||
| Maintenance capital expenditures (g) |
(47,267 | ) | (28,778 | ) | ||||
| Growth capital expenditures (h) |
(94,180 | ) | (93,541 | ) | ||||
| Principal payments on debt (i) |
(38,309 | ) | (32,505 | ) | ||||
| Distributions to non-affiliated owners of ETP (j) |
(148,221 | ) | (111,166 | ) | ||||
| Distributions to Energy Transfer Investments |
(26,750 | ) | (20,063 | ) | ||||
| Plus: |
||||||||
| Borrowings under ETP credit facilities for growth capital expenditures (k) |
94,180 | 93,541 | ||||||
| Proceeds from issuances of ETP common units |
234,258 | 131,040 | ||||||
| Pro forma available cash of Energy Transfer Equity |
$ | 92,133 | $ | 94,373 | ||||
| Expected Cash Distributions: |
||||||||
| Expected Distribution per Unit |
$ | 0.70 | $ | 0.70 | ||||
| Distributions to Public Common Unitholders (l) |
$ | 12,075 | $ | 9,056 | ||||
| Distributions to Common Units and Class B Units Held by Existing Owners |
68,817 | 51,613 | ||||||
| Distributions to General Partner Units |
444 | 333 | ||||||
| Total Distributions |
$ | 81,336 | $ | 61,002 | ||||
| Excess |
$ | 10,797 | $ | 33,371 | ||||
| Debt Covenant Ratios: |
||||||||
| Energy Transfer Partners |
||||||||
| Total Funded Debt / Consolidated EBITDA (m) |
3.41 | x | 3.51 | x | ||||
| Consolidated EBITDA / Consolidated Interest Expense (m) |
3.30 | x | 3.83 | x | ||||
| Energy Transfer Equity |
||||||||
| Total Funded Debt / Consolidated EBITDA (n) |
||||||||
| Consolidated EBITDA / Consolidated Interest Expense (n) |
||||||||
| (a) | Reflects net cash provided (used) by operating activities of Energy Transfer Equity, L.P., derived from its historical consolidated financial statements for the periods indicated without giving pro forma effect to the transaction described in footnote (d). |
| (b) | ETP maintains two revolving credit facilities that have an aggregate of $875 million in borrowing availability. ETP uses these revolving credit facilities to satisfy its working capital needs which allows it to avoid using cash flow from operations to satisfy its working capital needs. Therefore, we do not reflect any adjustments to cash available for distributions as a result of these requirements. |
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| (c) | Reflects an adjustment to our Consolidated Adjusted EBITDA for approximately $2.5 million in incremental ongoing annual expenses associated with being a public company, including, among other things, estimated incremental accounting and audit fees, director and officer liability insurance and other miscellaneous fees. |
| (d) | Reflects pro forma adjustments for the business combination with Heritage on January 20, 2004, ETP’s acquisition of TXU Fuel Company on June 1, 2004 and ETP’s acquisition of 98% of the general partner and limited partner interests in HPL on January 26, 2005. The results of operations for these transactions are reflected in our historical consolidated operating results beginning on the day we closed the transaction. We have included the results of these transactions in our results on a pro forma basis as if, for the fiscal year ended August 31, 2004, the transactions occurred on September 1, 2003 and, for the nine month period ended May 31, 2005, as if the transactions occurred on September 1, 2004. Please see the Energy Transfer Equity, L.P. and Subsidiaries Unaudited Pro Forma Consolidated Financial Statements beginning on page F-4. The pro forma financial data should not be considered indicative of the historical results we would have had or the future results that we will have after this offering. We have set forth below a summary of our pro forma EBITDA adjustments to reflect these transactions: |
| Fiscal Year Ended August 31, 2004 |
||||||||||||||||||||||||||
| Energy Transfer Equity, L.P. |
Heritage |
Heritage Holdings |
TXU Fuel Company |
HPL |
Adjustments |
Pro Forma |
||||||||||||||||||||
| Net income |
$ | 450,217 | $ | 22,644 | $ | 3,319 | $ | 16,122 | $ | (187,385 | ) | $ | (280,666 | ) | $ | 24,251 | ||||||||||
| Gain on Heritage Transaction |
(395,253 | ) | — | — | — | — | 395,253 | 0 | ||||||||||||||||||
| Depreciation and amortization |
56,242 | 15,389 | — | 3,986 | 12,037 | 18,022 | 105,676 | |||||||||||||||||||
| Interest expense |
41,217 | 12,754 | — | 884 | 40 | 64,814 | 119,709 | |||||||||||||||||||
| Income taxes expense |
2,792 | 20 | 2,245 | 9,881 | (66,428 | ) | 56,763 | 5,273 | ||||||||||||||||||
| Non-cash compensation expense |
42 | 1,232 | — | — | — | — | 1,274 | |||||||||||||||||||
| Interest income and other |
(516 | ) | 66 | (346 | ) | 138 | (3,050 | ) | 346 | (3,362 | ) | |||||||||||||||
| (Gain) loss on disposal of assets |
1,006 | 240 | — | — | — | (100 | ) | 1,146 | ||||||||||||||||||
| Minority interests |
— | 178 | — | — | — | — | 178 | |||||||||||||||||||
| Depreciation, amortization and interest of investee |
440 | 322 | — | — | — | — | 762 | |||||||||||||||||||
| Depreciation, amortization and interest of discontinued operations |
2,249 | — | — | — | — | — | 2,249 | |||||||||||||||||||
| Depreciation, amortization and interest of minority interest |
— | — | — | — | — | (5,459 | ) | (5,459 | ) | |||||||||||||||||
| Consolidated Adjusted EBITDA |
$ | 158,436 | $ | 52,845 | $ | 5,218 | $ | 31,011 | $ | (244,786 | ) | $ | 248,973 | $ | 251,697 | |||||||||||
| Nine Months Ended May 31, 2005 |
||||||||||||||||
| Energy Transfer Equity, L.P. |
HPL |
Adjustments |
Pro Forma |
|||||||||||||
| Net income |
$ | 121,879 | $ | 32,232 | $ | (47,016 | ) | $ | 107,095 | |||||||
| Gain on sale of discontinued operations, net of income tax expense |
(104,562 | ) | — | — | (104,562 | ) | ||||||||||
| Minority interest expense on gain on sale of discontinued operations |
49,686 | — | — | 49,686 | ||||||||||||
| Depreciation and amortization |
76,874 | 4,953 | 3,707 | 85,534 | ||||||||||||
| Interest expense |
66,350 | 866 | 32,415 | 99,631 | ||||||||||||
| Income tax expense on continuing operations |
5,168 | 15,608 | (15,000 | ) | 5,776 | |||||||||||
| Other (income) expense, net |
(67 | ) | (4,390 | ) | — | (4,457 | ) | |||||||||
| Non-cash compensation expense |
1,206 | — | — | 1,206 | ||||||||||||
| Loss on disposal of assets |
665 | — | — | 665 | ||||||||||||
| Depreciation, amortization and interest of investee |
493 | — | — | 493 | ||||||||||||
| Depreciation, amortization and interest of discontinued operations |
1,547 | — | — | 1,547 | ||||||||||||
| Depreciation, amortization and interest of minority interest |
(7,578 | ) | — | — | (7,578 | ) | ||||||||||
| Loss on extinguishment of debt |
6,550 | — | — | 6,550 | ||||||||||||
| Consolidated Adjusted EBITDA |
$ | 218,211 | $ | 49,269 | $ | (25,894 | ) | $ | 241,586 | |||||||
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| (e) | Reflects an annualized increase to interest expense of approximately $78.5 million as a result of interest expense related to: (i) ETP’s issuance of $750 million of its 5.95% senior notes on January 18, 2005 and the application of the net proceeds therefrom to repay other indebtedness of ETP, (ii) additional borrowings by ETP during the fiscal year ended August 31, 2004 and the nine months ended May 31, 2005 to finance ETP’s business combination with Heritage on January 20, 2004, ETP’s acquisition of TXU Fuel Company on June 1, 2004 and ETP’s acquisition of controlling interests in HPL on January 26, 2005, under ETP’s credit facilities at a weighted average interest rate of approximately 4.7%, (iii) our term loan borrowing dated June 16, 2005 of $600.0 million less the assumed paydown amount of $240 million at a weighted average interest rate of approximately 6.0%, and (iv) this offering and the resulting use of proceeds, including the full exercise of the underwriters’ option to purchase additional common units. |
| (f) | In computing our estimated cash tax expense for the fiscal year ended August 31, 2004 and the nine months ended May 31, 2005, we have given effect to the current quarterly distributions of $0.50 per unit by ETP and we have considered the flow through nature of taxable income from ETP. |
| (g) | Includes actual maintenance capital expenditures of $22.5 million and $25.0 million for the fiscal year ending August 31, 2004 and the nine months ended May 31, 2005, respectively. Also includes estimated additional maintenance capital expenditures of $12.0 million and $3.8 million for the fiscal year ended August 31, 2004 and the nine months ended May 31, 2005, respectively, to integrate the operations of recently completed acquisitions, including ETP’s acquisition of TXU Fuel Company and controlling interests in HPL. The estimated additional maintenance capital expenditures are derived based on our experience in integrating acquisitions as well as the specific characteristics of the businesses we have acquired. |
| (h) | Reflects growth capital expenditures for the fiscal year ended August 31, 2004 of $87.1 million as adjusted for the business combination with Heritage on January 20, 2004, ETP’s acquisition of TXU Fuel Company on June 1, 2004 and ETP’s acquisition of 98% of the general partner and limited partner interests in HPL on January 26, 2005 and $93.5 million for the nine months ended May 31, 2005. The growth capital expenditures for the fiscal year ended August 31, 2004 include $67.0 million associated with capital expenditures related to ETP’s East Texas Pipeline expansion project. The growth capital expenditures for the nine months ended May 31, 2005 include capital expenditures of approximately $30.9 million related to ETP’s Fort Worth Basin expansion project. Growth capital expenditures do not include cash amounts paid in connection with acquisitions. |
| (i) | Reflects the principal payments on ETP’s indebtedness for the fiscal year ended August 31, 2004 and the nine months ended May 31, 2005, respectively. These principal payments were refinanced through borrowings under ETP’s credit facilities. |
| (j) | Reflects the cash distributions from ETP to its unitholders other than us based upon the current quarterly distributions of $0.50 per unit ($2.00 per unit on an annualized basis). |
| (k) | Reflects borrowings incurred under ETP’s revolving credit facility (the “ETP Revolving Credit Facility”) to finance its growth capital expenditures. Because ETP distributes substantially all of its available cash on a quarterly basis, ETP has historically financed its growth capital expenditures through the use of external financing alternatives, including borrowings under its credit facilities and the public and private capital markets. In the future, ETP anticipates that it will continue to utilize these external sources of financing to fund its acquisition growth strategy and expects to refinance all of its debt as it matures. After giving effect to this offering, including the full exercise of the overallotment option, our consolidated principal debt maturities for each of the fiscal years ended August 31 would be as follows (in millions): |
| 2006 |
$ | 39.2 | |
| 2007 |
$ | 86.7 | |
| 2008 |
$ | 45.9 | |
| 2009 |
$ | 43.1 | |
| 2010 |
$ | 513.6 | |
| Thereafter |
$ | 847.3 |
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| (l) | The table below sets forth the assumed number of outstanding common units, Class B units and general partner units upon the closing of this offering and the estimated aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate. |
| Number of Units |
Annual Distributions | ||||
| Estimated distributions on publicly held common units |
17,250,000 | $ | 12,075,000 | ||
| Estimated distributions on common units and Class B units held by our existing owners |
98,310,061 | 68,817,043 | |||
| Estimated distributions on general partners units |
634,000 | 443,800 | |||
| Total |
116,194,061 | $ | 81,335,843 | ||
| (m) | The ETP Revolving Credit Facility requires that, on the last day of each of ETP’s fiscal quarters, the ratio of ETP’s Consolidated Funded Debt (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to ETP’s Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must be no greater than 4.50 to 1.00 except that, on the last day of any fiscal quarter in which ETP or its subsidiaries makes an acquisition with a purchase price of $50.0 million or more, such ratio must be no greater than 5.0 to 1.0. You should note that ETP’s Consolidated Debt to ETP’s Consolidated EBITDA for purposes of ETP’s financial covenants includes only the operations of ETP and its subsidiaries and excludes our operations and those of our subsidiaries that are not subsidiaries of ETP. In addition, this facility requires that the ratio of ETP’s Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to ETP’s Consolidated Interest Expense (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must not be less than 3.0 to 1.0. ETP satisfied its leverage ratio covenants for the fiscal year ended August 31, 2004 and for the nine months ended May 31, 2005 and therefore was permitted to make the cash distributions at the levels it distributed during these periods. |
| (n) | Our term loan agreement requires that, on the last day of the specified fiscal quarter, the ratio of our Consolidated Funded Debt (as defined in our term loan agreement) to our Consolidated EBITDA (as defined in our term loan agreement) for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. Our term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of our Consolidated EBITDA (as defined in our term loan agreement) to our Consolidated Interest Expense (as defined in our term loan agreement) must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008. Following completion of this offering, we expect to enter into a new credit facility, which will provide us with a $100.0 million revolving line of credit. This facility is exclusively for our use and may not be drawn on by ETP. This facility is expected to have a 36-month maturity with quarterly interest payments required but no required principal payments until maturity. The new credit facility is expected to include terms substantially similar to those existing for our term loan described in this prospectus. |
As a result of the factors described in “Estimated Consolidated Adjusted EBITDA,” “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA,” and “Assumptions and Considerations” below, we believe we will be able to pay an initial quarterly distribution of $0.175 per unit for each quarter in the year following consummation of this offering.
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Estimated Consolidated Adjusted EBITDA
In order to fund distributions to our common unitholders at our initial rate of $0.175 per unit per complete quarter, our Consolidated Adjusted EBITDA for the year following this offering must be at least $459.3 million. We define Consolidated Adjusted EBITDA as earnings before income taxes, plus the following items:
| • | net interest expense (inclusive of write-off of deferred financing costs, interest expense related to make whole premium charge, less gain from termination of interest rate swap agreement and interest income); |
| • | interest of non-controlling partners in ETP’s net income; |
| • | gain on issuance of units of ETP; |
| • | depreciation and amortization expense; and |
| • | compensation charges for issuances of ETP units to ETP’s employees. |
Gain (loss) on sales of property, plant and equipment and provisions for doubtful accounts are considered non-cash items within Net Cash Provided (Used) by Operating Activities in our statement of cash flows and are also excluded for purposes of determining Estimated Consolidated Adjusted EBITDA. Similarly, changes in working capital accounts are not included in the Estimated Consolidated Adjusted EBITDA, and therefore are reconciling items in the reconciliation of Net Cash Provided (Used) by Operating Activities and Estimated Consolidated Adjusted EBITDA. Non-cash compensation expense represents charges for the value of the common units awarded under ETP’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement.
Consolidated Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with accounting principles generally accepted in the United States as those items are used to measure operating performance, liquidity or ability to service debt obligations.
In the table below entitled “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA,” we estimate that our Consolidated Adjusted EBITDA will be at least $459.3 million for the four fiscal quarters ended August 31, 2006. We refer to this amount as our “Estimated Consolidated Adjusted EBITDA.” We have also determined that if our Estimated Consolidated Adjusted EBITDA for such period is at or above our estimate, we would be permitted to make cash distributions under the restricted payments covenants in our term loan agreement at the initial distribution rate of $0.175 per unit per quarter for such period, and ETP would be permitted under its credit facilities to pay sufficient cash distributions to us to enable us to make distributions to our unitholders at this level.
In developing our Estimated Consolidated Adjusted EBITDA, we have included maintenance and growth capital expenditures for the four fiscal quarters ended August 31, 2006. Maintenance capital expenditures are capital expenditures made on an ongoing basis to maintain current operations, which do not increase operating capacity or revenues from existing levels. Growth capital expenditures consist of capital expenditures we expect to make to expand the operating capacity of our current operations. While we have presented additional borrowings to fund growth capital expenditures, we have not presented the additional cash flow we would expect to realize as a result of such expenditures.
You should read footnote (a) to the table below for a discussion of the material assumptions underlying our belief that we will be able to generate our Estimated Consolidated Adjusted EBITDA. Our belief is based on several assumptions and reflects our judgment of conditions we expect to exist and the course of action we expect to take. While we believe that these assumptions are reasonable in light of our current expectations regarding future events, the assumptions underlying our Estimated Consolidated Adjusted EBITDA are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are
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not realized, the actual available cash that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make distributions on the common units at the initial distribution rate, or at any level, in which event the market price of the common units may decline materially. Consequently, the statement that we believe that we will have sufficient available cash to pay the initial distribution on the common units for each quarter through August 31, 2006 should not be regarded as a representation by us or the underwriters or any other person that we will declare and make such a distribution.
When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA” below.
Estimated Cash Available to Pay Distributions Based Upon
Estimated Consolidated Adjusted EBITDA
| Twelve Months August 31, 2006 | |||
| (dollars in thousands, except per unit data) | |||
| Estimated Consolidated Adjusted EBITDA (a) |
$ | 459,334 | |
| Less: |
|||
| Cash interest expense (b) |
138,866 | ||
| Estimated principal payments on debt (c) |
39,200 | ||
| Estimated cash income taxes (d) |
7,000 | ||
| Maintenance capital expenditures (e) |
37,000 | ||
| Growth capital expenditures (f) |
500,000 | ||
| Acquisition capital expenditures (g) |
20,000 | ||
| Distributions to non-affiliated owners of ETP (i) |
148,221 | ||
| Distributions to Energy Transfer Investments (i) |
26,750 | ||
| Plus: |
|||
| Borrowings for acquisitions (j) |
20,000 | ||
| Net borrowings under loan agreements (j) |
388,039 | ||
| Proceeds from equity offering (h) |
131,000 | ||
| Available Cash of Energy Transfer Equity |
81,336 | ||
| Expected Cash Distributions by Energy Transfer Equity |
81,336 | ||
| Expected distribution per common unit |
0.700 | ||
| Distributions to our general partner |
444 | ||
| Distributions to our public common unitholders |
12,075 | ||
| Distributions to common units and Class B units held by our pre-existing owners |
68,817 | ||
| Total distributions (k) |
$ | 81,336 | |
| Debt Covenant Ratios: |
|||
| Energy Transfer Partners |
|||
| Total Funded Debt/Consolidated EBITDA (l) |
3.84x | ||
| Consolidated EBITDA/Consolidated Interest Expense (l) |
4.49x | ||
| Energy Transfer Equity |
|||
| Total Funded Debt/Consolidated EBITDA (m) |
4.63x | ||
| Consolidated EBITDA/Consolidated Interest Expense (m) |
3.70x | ||
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| (a) | We believe that our Estimated Consolidated Adjusted EBITDA for the twelve months ending August 31, 2006 will be not less than $459.3 million. This amount of Estimated Consolidated Adjusted EBITDA is approximately $203 million more than the pro forma Consolidated Adjusted EBITDA we generated for the fiscal year ended August 31, 2004. In order for us to generate the Estimated Consolidated Adjusted EBITDA, we believe that ETP must achieve a minimum base level of $461.5 million in EBITDA. |
| Our minimum base level estimate of $459.3 million in Consolidated Adjusted EBITDA for the twelve months ending August 31, 2006 is intended to be an indicator or benchmark of the amount management considers to be the lowest amount of Consolidated Adjusted EBITDA needed to generate sufficient available cash to make cash distributions to our common unitholders at our initial distribution rate of $0.175 per common unit per quarter (or $0.70 per common unit on an annualized basis). The baseline estimates of Consolidated Adjusted EBITDA should not be viewed as management’s projection of operating earnings of us or ETP. Our management believes that our actual financial performance during the twelve months ending August 31, 2006 will exceed the minimum base level amount. To calculate our baseline estimate of Consolidated Adjusted EBITDA for the estimated period, we have intentionally excluded the EBITDA of the significant growth capital projects that ETP has previously announced. |
Our Estimated Consolidated Adjusted EBITDA is based on a number of significant assumptions that are set forth below:
| • | ETP will pay a quarterly cash distribution of $0.50 per ETP common unit for each of the four quarters in the four-quarter period ending August 31, 2006, which quarterly distribution amount is equal to the most recently declared cash distribution of $0.50 per ETP common unit for the quarter ended August 31, 2005. As a result, we estimate that the amount of cash distribution that we receive from ETP will be equal to or greater than $26.4 million during this period. We have also assumed that Energy Transfer Partners GP will maintain its 2% general partner interest in ETP by making proportionate cash contributions to ETP in connection with ETP’s equity issuances. |
| • | ETP will sell a minimum of 270 MMBtu/d of natural gas and a minimum of 400 bbls/d of NGLs in its midstream segment for the fiscal year ending August 31, 2006, as compared to the 2,893 MMBtu/d of natural gas and 13 bbls/d of NGLs sold on a pro forma basis for the fiscal year ending August 31, 2004 and 2,565 MMBtu/d of natural gas and 15 bbls/d of NGLs transported on a pro forma basis for the fiscal year ending August 31, 2003. |
| • | ETP will transport a minimum of 3,750 MMBtu/d of natural gas in its transportation segment for the fiscal year ending August 31, 2006, as compared to the 2,950 MMBtu/d of natural gas transported on a pro forma basis for the fiscal year ending August 31, 2004 and 2,871 MMBtu/d of natural gas transported on a pro forma basis for the fiscal year ending August 31, 2003. |
| • | ETP will sell a minimum of 420 million retail gallons of propane for fiscal year ending August 31, 2006, as compared to the 400 million retail gallons sold on a pro forma basis for the fiscal year ending August 31, 2004 and 376 million retail gallons sold on a pro forma basis for the fiscal year ending August 31, 2003. |
| • | ETP will realize EBITDA of not less than $75 million from its midstream segment, $275 million from its transportation segment and $125 million from its retail propane segment for the fiscal year ended August 31, 2006 as compared to $79.2 million from its midstream segment, $63.7 million from its transportation segment and $114.5 million from its retail propane segment for the fiscal year ended August 31, 2004 and $57.0 million from its midstream segment, $20.0 million from its transportation segment and $110.9 million from its retail propane segment for the fiscal year ended August 31, 2003. |
| • | ETP will not experience net customer losses during our fiscal year ending August 31, 2006. |
| • | ETP will experience a number of heating degree days no less than the 15-year average of heating degree days in its area of operations for our fiscal year ending August 31, 2006. |
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| • | ETP’s maintenance capital expenditures will not exceed $37 million for the fiscal year ending August 31, 2006 as compared to ETP’s maintenance capital expenditures of $34.5 million and $22.6 million on a pro forma basis for our fiscal years ended August 31, 2004 and 2003, respectively. |
| • | ETP’s growth capital expenditures will not exceed $500 million for the fiscal year ending August 31, 2006 as compared to ETP’s growth capital expenditures of $87.2 million and $4.2 million on a pro forma basis for our fiscal year ended August 31, 2004 and 2003, respectively. |
| • | We and ETP will remain in compliance with the restrictive financial covenants in our existing and future debt agreements such that our ability to pay distributions to our partners will not be encumbered. |
| • | Our average interest rates will not exceed the rates we have assumed, which range between 5.5% and 6.0%, and our consolidated cash interest expense will not exceed approximately $138.9 million for the fiscal year ending August 31, 2006. |
| • | We and ETP will be able to access equity capital markets and be able to obtain financing arrangements to support our commercial goals, including growth capital expenditures, on reasonable terms. |
| • | Our incremental general and administrative expenses associated with public company reporting and filing requirements will not exceed $2.5 million for the fiscal year ending August 31, 2006. |
| • | There will not be any new federal, state or local regulation of portions of the energy industry in which we and ETP operate, or an interpretation of existing regulation, that will be materially adverse to our or ETP’s business. |
| • | There will not be any major adverse change in the portions of the energy industry in which we and ETP operate resulting from supply or production disruptions, reduced demand for our products or services, or from significant changes in the market prices of natural gas or NGLs. |
| • | Market, regulatory, insurance and overall economic conditions will not change substantially. |
We cannot assure you that any of the assumptions summarized above, or any other assumptions upon which Estimated Consolidated Adjusted EBITDA is based, will prove to be correct. If the assumptions are incorrect, we may not have sufficient cash to make the contemplated distributions.
| (b) | Our estimated consolidated cash interest expense assumes cash interest expense for the next four quarters to be approximately $138.9 million. Our cash interest is comprised of the following components: |
| (i) | Approximately $21.6 million associated with the outstanding borrowings under our term loan which is expected to have approximately $360.0 million outstanding after the application of $240.0 million of the net proceeds of this offering to repay a portion of the outstanding borrowings under the term loan. The term loan bears interest at a LIBOR-based floating rate currently assumed to be approximately 2.25% on average through August 31, 2006. |
| (ii) | Approximately $44.6 million of interest expense associated with ETP’s $750.0 million of 5.95% senior unsecured notes. |
| (iii) | Approximately $22.6 million of interest expense associated with ETP’s $400.0 million of 5.65% senior unsecured notes. |
| (iv) | Approximately $18.4 million of interest expense related to borrowings under ETP’s current credit agreement, including interest expense of additional $15.0 million in interest expense related to borrowings primarily related to growth capital expenditures and the additional interest associated with the annual commitment fee of approximately 0.3% on the $325.0 million of available revolving credit under ETP’s credit facility. We expect that ETP will finance all of its growth capital expenditures through borrowings under its credit facilities. |
| (v) | Approximately $24.7 million of interest expense related to various series of senior secured notes issued by a subsidiary of ETP based on the scheduled interest payments payable during the period and the |
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| fixed annual interest rates ranging from 7.17% to 8.87% per annum. The aggregate unpaid principal amount of these notes as of August 31, 2006 is projected to be $262.6 million based on the scheduled repayments of principal on these notes during the period. |
| (vi) | Approximately $6.0 million of interest expense in other ETP borrowings at various rates of interest. |
| (c) | Represents $39.2 million of principal payments on ETP’s indebtedness. As noted in footnote (j) below, ETP expects to fund these principal payments with borrowings under its credit facilities. After giving effect to this offering, including the full exercise of the overallotment option, and the borrowings of $388.0 million related to expected growth capital expenditures, our consolidated principal payment requirements for each of the fiscal years ending August 31 would be as follows (in thousands): |
| 2006 |
$39.2 | |
| 2007 |
$86.7 | |
| 2008 |
$45.9 | |
| 2009 |
$43.1 | |
| 2010 |
$513.6 | |
| Thereafter |
$847.3 |
| In addition, it is our expectation that our existing debt and ETP’s existing debt will be refinanced as it matures, and therefore no repayments of debt are presented in the table. |
| (d) | Our annual income tax expense is the result of the federal income tax obligations of our consolidated subsidiaries. In computing our estimated cash income tax expense, we have considered distributions to us from ETP based upon the current quarterly distribution rate of $0.50 per unit for each quarter during the four-quarter period ending August 31, 2006 and the flow-through nature of taxable income from ETP. |
| (e) | We currently expect that our consolidated maintenance capital expenditures will be approximately $37.0 million for the fiscal year ending August 31, 2006 in comparison to $22.5 million and $25.0 million in the fiscal year ended August 31, 2004 and the nine month period ended May 31, 2005, respectively. The increased expected maintenance capital expenditures for the fiscal year ending August 31, 2006 primarily reflects increased pipeline integrity inspections and repairs. |
| (f) | This reflects our anticipated expenditure of $500.0 million for growth capital for the fiscal year ending August 31, 2006. During the fiscal year ended August 31, 2004 and the nine-month period ended May 31, 2005, we expended a significantly lower level of growth capital on projects associated with, among other things, the construction of the East Texas Pipeline and the Fort Worth Basin Pipeline. |
| Our anticipated consolidated growth capital expenditures of approximately $500 million for the fiscal year ending August 31, 2006, which consists primarily of capital expenditures related to ETP’s recently announced expansion projects involving the construction of approximately 264 miles of pipeline and the addition of approximately 40,000 horsepower of compression that will increase pipeline transportation access for the natural gas producers in the Bossier Sands and Barnett Shale basins in east and north Texas of various intrastate and interstate markets. |
| (g) | Consistent with its acquisition strategy, ETP is continuously pursuing strategic acquisitions that it expects to be accretive to its earnings. Since the inception of ETP’s predecessor in 1996 and through May 31, 2005, ETP has acquired three significant natural gas transportation pipeline systems for aggregate consideration of approximately $1.6 billion and approximately 105 propane-related acquisitions for aggregate consideration of approximately $720 million. While ETP expects to continue to pursue acquisitions during its fiscal year ending August 31, 2006, because of the uncertain nature of the acquisition environment, we have only included an estimate of future retail propane acquisition capital expenditure requirements. If ETP is successful in completing additional acquisitions, ETP anticipates its primary source of consideration will be through commercial borrowings, other debt and common unit issuances. While the initial funding of its acquisitions may consist of debt financing, ETP’s financial strategy is to finance acquisitions equally with equity and debt, and ETP would expect to repay such debt with proceeds of equity issuances to achieve this |
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| relatively balanced financing ratio. If ETP is unable to finance its growth through external sources or is unable to achieve its targeted debt/equity ratios our cash available to pay distributions may be negatively impacted. |
| (h) | Represents the proceeds of an equity issuance of 3,640,000 ETP common units at $36.00 per unit, net of fees and expenses. |
| (i) | Reflects the cash distributions from ETP to its unitholders, other than us and Energy Transfer Investments, based upon the current quarterly distribution of $0.50 per unit for each quarter during the four-quarter period ending August 31, 2006, or $2.00 per unit on an annualized basis, and based upon the assumption that we purchase 3.64 million common units of ETP upon the closing of this offering. |
| (j) | As ETP has historically financed internal growth and acquisitions through the use of external financing sources, including borrowings under its credit facilities and the issuance of debt and equity securities, and anticipates continuing to do so, we have shown estimated borrowings for these purposes as a source of cash in the table above. Specifically, we expect that ETP will borrow the $408.0 million necessary for its projected $388.0 million of growth capital expenditures and $20.0 million of acquisitions for its fiscal year ended August 31, 2006. |
| (k) | Represents the amount required to fund distributions to our unitholders for four quarters based upon our initial cash distribution rate of $0.175 per unit ($0.70 per unit annually) and assuming the underwriters’ option to purchase additional common units has been exercised in full. |
| (l) | The ETP Revolving Credit Facility requires that the ratio of ETP’s Consolidated Funded Debt (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to ETP’s Consolidated EBITDA for the four fiscal quarters most recently ended must be no greater than 4.50 to 1.00 except that, on the last day of any fiscal quarter in which ETP or its subsidiaries makes an acquisition with a purchase price of $50.0 million or more, such ratio must be no greater than 5.0 to 1.0. You should note that ETP’s Consolidated Funded Debt to ETP’s Consolidated EBITDA for purposes of ETP’s financial covenants includes only the operations of ETP and its subsidiaries and excludes our operations and those of our subsidiaries that are not subsidiaries of ETP. In addition, this Revolving Credit Facility requires that the ratio of ETP’s Consolidated EBITDA to ETP’s Consolidated Interest Expense (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must not be less than 3.0 to 1.0. As indicated in the table, ETP’s Consolidated EBITDA would have been sufficient to satisfy the ratios required by the ETP Revolving Credit Facility and permit the payment to us of cash distributions sufficient to enable us to make our intended distribution. |
| (m) | Our term loan agreement requires that, on the last day of the specified fiscal quarter, the ratio of our Consolidated Funded Debt (as defined in our term loan agreement) to our Consolidated EBITDA for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. Our term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of our Consolidated EBITDA to our Consolidated Interest Expense must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008. Following the completion of this offering, we expect to enter into a new credit facility that will provide us with a $100.0 million revolving line of credit. This facility is exclusively for our use and may not be drawn on by ETP. This facility is expected to have a 36-month maturity with quarterly interest payments required but no required principal payments until maturity. The credit facility is expected to include terms substantially similar to those existing in our term loan agreement described in this prospectus. |
Assumptions and Considerations
We believe that our partnership interests, including incentive distribution rights, in ETP will generate sufficient cash flow to enable us to pay our initial quarterly distribution of $0.175 per unit on all of our units for
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the four quarters ending August 31, 2006. Our belief is based on a number of current assumptions that we believe to be reasonable over the next four quarters. While we believe that these assumptions are generally consistent with the actual performance of ETP and are reasonable in light of our current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that ETP generates, and thus the cash we would receive from our ownership of ETP’s general partner interest, incentive distribution rights and common units, could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make our initial quarterly and annual distributions on our units, in which event the market price of our units may decline materially. Consequently the statement that we believe that we will have sufficient available cash to pay the initial distribution on our units for each quarter through August 31, 2006 should not be regarded as a representation by us or the underwriters or any other person that we will make such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” in this prospectus.
Our Sources of Distributable Cash
Our only cash-generating assets currently consist of our partnership interests in ETP. Therefore, our cash flow and resulting ability to make distributions initially will be completely dependent upon the ability of ETP to make distributions in respect of those interests and rights. The actual amount of cash that ETP will have available for distribution will primarily depend on the amount of cash it generates from operations. The actual amount of this cash will fluctuate from quarter to quarter based on certain factors, including:
| • | fluctuations in cash flow generated by ETP’s operating activities; |
| • | the level of capital expenditures ETP makes; |
| • | the cost of capital used to fund any acquisitions; |
| • | debt service requirements; |
| • | fluctuations in working capital needs; |
| • | restrictions on distributions contained in ETP’s credit facility and senior notes; |
| • | ETP’s ability to borrow under its working capital facility to make distributions; |
| • | prevailing economic conditions; and |
| • | the amount, if any, of cash reserves established by ETP’s general partner in its discretion for the proper conduct of its business. |
As ETP makes quarterly distributions of available cash from operating surplus to its partners, we receive our share of such distributions in proportion to our ownership interests in ETP. Upon completion of this offering, we will own, directly or indirectly:
| • | a 100% membership interest in Energy Transfer Partners, LLC, the general partner of Energy Transfer GP, L.P., which currently owns a 2% general partner interest in ETP; |
| • | 36,413,840 ETP common units, representing approximately 33% of the outstanding common units in ETP; and |
| • | 50% of the ETP incentive distribution rights, which entitles us to receive our pro rata share of any cash distributed by ETP as certain target distribution levels are reached in excess of $0.25 per ETP unit in any quarter. |
Our Incentive Distribution Rights Related to ETP’s Cash Distributions. The incentive distribution rights we own in ETP represent our right to receive an increasing percentage of ETP’s quarterly distributions of available
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cash from operating surplus after ETP has made cash distributions in excess of its first target distribution level. If for any quarter ETP has distributed available cash from operating surplus to ETP common unitholders in an amount equal to the minimum quarterly distribution of ETP, then ETP will distribute any additional available cash from operating surplus for that quarter among ETP unitholders, ETP’s general partner and the holder of ETP’s incentive distribution rights in the following manner:
| • | First, 98% to all ETP unitholders, pro rata, and 2% to ETP’s general partner, until each ETP unitholder receives a total of $0.275 per unit for that quarter (the “first target distribution”); |
| • | Second, 85% to all ETP unitholders, pro rata, 2% to ETP’s general partner and 13% to the holders of the incentive distribution rights, pro rata, until each ETP unitholder receives a total of $0.3175 per ETP unit for that quarter (the “second target distribution”); |
| • | Third, 75% to all ETP unitholders, pro rata, 2% to ETP’s general partner and 23% to the holders of the incentive distribution rights, pro rata, until each ETP unitholder receives a total of $0.4125 per ETP unit for that quarter (the “third target distribution”); and |
| • | Thereafter, 50% to all ETP unitholders, pro rata, 2% to ETP’s general partner and 48% to the holder of the incentive distribution rights, pro rata. |
For a further description of ETP’s cash distribution policy, see “Energy Transfer Partners’ Cash Distribution Policy.”
Hypothetical Allocations of Distributions to Our Unitholders and ETP’s Unitholders. The table set forth below illustrates the percentage allocations among (i) the owners of ETP, other than us, and (ii) Energy Transfer Equity, L.P. as a result of certain assumed quarterly distribution payments per common unit made by ETP, including the target distribution levels contained in ETP’s partnership agreement. This information assumes:
| • | ETP has 110,534,514 total units outstanding, representing the number of ETP units outstanding at the closing of this offering; and |
| • | our ownership of (i) 36,413,840 ETP common units, comprising approximately 33% of the outstanding common units in ETP, (ii) the 2% general partner interest in ETP and (iii) 50% of the incentive distribution rights of ETP. |
The percentage interests shown for us and the other ETP unitholders for the minimum quarterly distribution amount are also applicable to distribution amounts that are less than the minimum quarterly distribution. The amounts presented below are intended to be illustrative of the way in which we are entitled to an increasing share of distributions from ETP as total distributions from ETP increase and are not intended to represent a prediction of future performance.
| Distribution Level |
ETP Quarterly Distribution Per Unit |
Distributions to Owners of ETP Other Than Us as a Percentage of Distributions |
Distributions to Energy Transfer Equity, L.P. as a Percentage of Total Distributions (1) |
||||||
| Minimum Quarterly Distribution |
$ | 0.2500 | 65.6 | % | 34.4 | % | |||
| First Target Distribution |
$ | 0.2750 | 65.6 | % | 34.4 | % | |||
| Second Target Distribution |
$ | 0.3175 | 63.3 | % | 36.7 | % | |||
| Third Target Distribution |
$ | 0.4125 | 61.7 | % | 38.3 | % | |||
| Other Hypothetical Distributions |
$ | 0.5000 | 57.5 | % | 42.5 | % | |||
| (1) | Includes distributions made with respect to our ownership of the 2% general partner interest in ETP, our ownership of 33% of ETP’s limited partnership interests and our ownership of 50% of the incentive distribution rights of ETP. |
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PARTNERSHIP AGREEMENT PROVISIONS
RELATING TO CASH DISTRIBUTIONS
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
Our partnership agreement requires that, within 50 days after the end of each quarter beginning with the quarter ending August 31, 2005, we distribute all of our available cash to the holders of record of our common units and Class B units on the applicable record date.
Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:
| • | less the amount of cash reserves necessary or appropriate in the reasonable discretion of our general partner to: |
| • | satisfy general, administrative and other expenses and debt service requirements; |
| • | permit Energy Transfer Partners GP to make capital contributions to ETP in order to maintain its 2% general partner interest as required by ETP’s partnership agreement upon the issuance of additional partnership securities by ETP; |
| • | comply with applicable law or any debt instrument or other agreement; |
| • | provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters; and |
| • | otherwise provide for the proper conduct of our business; |
| • | plus all cash on hand immediately prior to the date of the distribution of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners. |
As of the closing of this offering, we will have Class B units outstanding which had been issued under our Class B Unit Incentive Plan. See “Management—Energy Transfer Equity—Executive and Incentive Compensation.” Each Class B unit will represent a limited partner interest in us and will be entitled to receive quarterly cash distributions in the same amount as the quarterly cash distributions we make on each common unit. Each Class B unit will be allocated a portion of our income, gain, loss, deduction and credit in a pro rata basis with each common unit, and each Class B unit will be entitled to receive distributions upon liquidation in the same manner as each common unit. Each Class B unit will also have the same voting rights as a common unit. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit. The Class B units will not be subject to vesting. The Class B units, unlike the common units, will have a zero initial capital account balance.
As of the date of this offering, our general partner will be entitled to 0.50% of all distributions that we make prior to our liquidation. This general partner interest will be represented by 634,000 general partner units. The
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general partner’s initial 0.50% interest in these distributions will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.50% general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.
Adjustments to Capital Accounts
We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.
Distributions of Cash upon Liquidation
If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in the partnership agreement and by law and, thereafter, we will distribute any remaining proceeds to the unitholders and our general partner in accordance with their respective capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
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Index to Financial Statements
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
The table on the following page shows selected consolidated financial data for Energy Transfer Equity, L.P. and selected pro forma financial and operating data for the partnership after giving effect to material acquisitions and transactions as described below, in each case for the periods and as of the dates indicated. The selected historical statement of operations and cash flow data for the eleven months ended August 31, 2003 and the year ended August 31, 2004 and the balance sheet data as of August 31, 2003 and 2004 are derived from our audited financial statements. The selected historical statement of operations and cash flow data for the nine months ended September 30, 2002 and for the years ended December 31, 2000 and 2001 and balance sheet data as of September 30, 2002 and as of December 31, 2001 are derived from the audited financial statements of Aquila Gas Pipeline, the predecessor to Energy Transfer Partners. The selected historical statement of operations and cash flow data for the year ended December 31, 1999 and the balance sheet data as of December 31, 1999 and 2000 are from the unaudited consolidated financial statements of Aquila Gas Pipeline. The statement of operations, balance sheet, and cash flow data as of and for the nine months ended May 31, 2004 and 2005, are derived from our unaudited financial statements. The unaudited financial statements include all adjustments, consisting of normal, recurring accruals, which we consider necessary for fair presentation of our financial position and results of operations for these periods.
We have had no independent operating activities apart from those conducted by ETP, and at present our cash flows solely consist of distributions from ETP on the partnership interests, including the incentive distribution rights, that we own. Accordingly, the selected historical consolidated financial data set forth in the table on the following page primarily reflects the operating activities and results of operations of ETP. We reflect our ownership interest in ETP on a consolidated basis, which means that our financial results are combined with ETP’s financial results and the results of our other subsidiaries. The interest owned by non-controlling partners in ETP is reflected as a liability on our balance sheet, and the non-controlling partner’s share of income for ETP is reflected as an expense in our results of operations.
Our selected historical consolidated financial data includes the effect of the acquisitions ETP made during these periods from the date of each acquisition, but not on a pro forma or full period basis.
The unaudited summary pro forma statement of operations data for the year ended August 31, 2004 and for the nine months ended May 31, 2005 reflect our consolidated historical operating results as adjusted to give pro forma effect to the following transactions as if these transactions occurred on September 1, 2003:
| • | our business combination in January 2004 with Heritage Propane Partners, L.P., which we refer to as “Heritage;” |
| • | the acquisition in June 2004 by ETP of the TXU Fuel Company from TXU Corp. and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | the acquisition in January 2005 by ETP of the controlling interests in the companies that own the Houston Pipeline System and the related debt and equity financings by ETP to pay the purchase price for this acquisition; |
| • | our new term loan in the aggregate principal amount of $600.0 million, the payment of related expenses and the distribution of the net proceeds of such borrowings to our unitholders in June 2005; |
| • | the transfer of Class B limited partner interests in ETP GP to Energy Transfer Investments and to us, which entitle ETI and us to each receive 50% of the cash distributions attributable to the ownership of ETP’s incentive distribution rights; |
| • | a capital contribution of $119.7 million to be made by our equity owners prior to the closing of this offering; and |
| • | this offering and the application of the net proceeds of $266.3 million and related expenses as described under “Use of Proceeds.” |
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The unaudited pro forma summary balance sheet data as of May 31, 2005 reflect our consolidated historical balance sheet data as adjusted to give pro forma affect to the following transactions, in each case as if the following transactions occurred on May 31, 2005:
| • | our new term loan in the aggregate principal amount of $600.0 million, the payment of related expenses and the distribution of the net proceeds of such borrowings to our unitholders in June 2005; |
| • | the transfer of Class B limited partner interests in ETP GP to Energy Transfer Investments and to us, which entitle ETI and us to each receive 50% of the cash distributions attributable to the ownership of ETP’s incentive distribution rights; |
| • | a capital contribution of $119.7 million to be made by our equity owners prior to the closing of this offering; and |
| • | this offering and the application of the net proceeds of $266.3 million and related expenses as described under “Use of Proceeds.” |
For a description of all of the assumptions used in preparing the summary pro forma financial and operating data, you should read the notes to the pro forma financial statements for Energy Transfer Equity, L.P. The pro forma financial and operating data should not be considered as indicative of the historical results we would have had or the future results that we will have after this offering.
We derived the data in the following table from, and it should be read together with and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included in this prospectus. The Consolidated Statements of Operations for the years ended August 31, 2003 and 2004 have been restated to account for the sale of ETP’s Oklahoma gathering, treating and processing assets as discontinued operations. Operating results for the nine months ended May 31, 2005 are not necessarily indicative of the results that may be expected for our entire fiscal year ending August 31, 2005. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| Historical (a) |
Pro Forma |
|||||||||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity |
|||||||||||||||||||||||||||
| Year Ended December 31, |
Nine Months Ended September 30, 2002 |
Eleven Months Ended August 31, 2003 |
Year August 31, 2004 |
Year Ended August 31, 2004 |
||||||||||||||||||||||||
| 1999 |
2000 |
2001 |
||||||||||||||||||||||||||
| (unaudited) | (in thousands except per unit data) | (unaudited) | ||||||||||||||||||||||||||
| Statement of Operations Data: |
||||||||||||||||||||||||||||
| Revenues |
$ | 1,030,554 | $ | 1,758,530 | $ | 1,813,850 | $ | 933,099 | $ | 931,027 | $ | 2,346,957 | $ | 6,350,022 | ||||||||||||||
| Gross profit |
94,109 | 117,663 | 98,589 | 53,035 | 105,589 | 365,533 | 679,026 | |||||||||||||||||||||
| Depreciation and amortization |
27,061 | 30,049 | 30,779 | 22,915 | 11,870 | 56,242 | 105,676 | |||||||||||||||||||||
| Operating income |
30,795 | 31,024 | 42,990 | 2,862 | 55,501 | 130,806 | 219,490 | |||||||||||||||||||||
| Other income (expense): |
||||||||||||||||||||||||||||
| Interest expense |
(12,894 | ) | (12,098 | ) | (6,858 | ) | (3,931 | ) | (12,453 | ) | (41,217 | ) | (119,709 | ) | ||||||||||||||
| Gain on Energy Transfer Transactions |
— | — | — | — | — | 395,253 | — | |||||||||||||||||||||
| Minority interests in income from continuing operations |
— | — | — | — | — | (35,164 | ) | (76,122 | ) | |||||||||||||||||||
| Income from continuing operations before income tax (benefit) expense |
17,502 | 18,892 | 41,161 | 4,272 | 44,673 | 449,551 | 26,064 | |||||||||||||||||||||
| Income tax (benefit) expense (c) |
(5,913 | ) | (7,657 | ) | (15,403 | ) | (467 | ) | (4,432 | ) | (2,792 | ) | (5,273 | ) | ||||||||||||||
| Income from continuing operations |
$ | 11,589 | $ | 11,235 | $ | 25,758 | $ | 3,805 | $ | 40,241 | $ | 446,759 | $ | 20,791 | ||||||||||||||
| Income from continuing operations per |
— | — | — | — | $ | 0.25 | $ | 2.47 | $ | 0.18 | ||||||||||||||||||
| Cash distribution per share/unit |
— | — | — | — | $ | 0.03 | $ | 1.37 | ||||||||||||||||||||
| Balance Sheet Data (end of period): | (unaudited) | (unaudited) | ||||||||||||||||||||||||||
| Total assets |
$ | 620,920 | $ | 724,161 | $ | 633,260 | $ | 601,528 | $ | 604,140 | $ | 2,865,191 | ||||||||||||||||
| Current liabilities |
160,419 | 313,506 | 194,816 | 144,076 | 169,967 | 404,917 | ||||||||||||||||||||||
| Long-term debt |
163,273 | 110,721 | 66,250 | 66,250 | 196,000 | 1,071,158 | ||||||||||||||||||||||
| Stockholders’ equity/partners’ capital |
237,877 | 254,248 | 249,520 | 254,259 | 182,631 | 368,325 | ||||||||||||||||||||||
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| Historical (a) |
Pro Forma | ||||||||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity | ||||||||||||||||||||||||||
| Year Ended December 31, |
Nine Months Ended September 30, 2002 |
Eleven Months Ended August 31, 2003 |
Year August 31, 2004 |
Year Ended August 31, 2004 | |||||||||||||||||||||||
| 1999 |
2000 |
2001 |
|||||||||||||||||||||||||
| (unaudited) | (in thousands except per unit data) | (unaudited) | |||||||||||||||||||||||||
| Other Financial Data: | (unaudited) | ||||||||||||||||||||||||||
| EBITDA, as adjusted (unaudited) (3) |
$ | 57,457 | $ | 61,039 | $ | 78,798 | $ | 31,118 | $ | 77,382 | $ | 108,436 | $ | 264,363 | |||||||||||||
| Net cash provided by operating activities |
43,182 | 76,011 | 65,198 | 12,987 | 70,223 | 122,098 | |||||||||||||||||||||
| Net cash used in investing activities |
(13,785 | ) | (23,459 | ) | (20,727 | ) | (487 | ) | (340,806 | ) | (731,831 | ) | |||||||||||||||
| Net cash provided by (used in) financing activities |
(34,544 | ) | (52,552 | ) | (44,471 | ) | (12,500 | ) | 325,655 | 637,513 | |||||||||||||||||
| Capital expenditures: |
|||||||||||||||||||||||||||
| Maintenance and growth |
19,166 | 21,965 | 28,866 | 5,486 | 13,872 | 109,688 | |||||||||||||||||||||
| Acquisition |
1,980 | 0 | 337,148 | 681,835 | |||||||||||||||||||||||
| Energy Transfer Equity |
||||||||||||
| Consolidated Historical |
Pro Forma |
|||||||||||
| For the Nine Months Ended May 31, |
For the Nine Months Ended May 31, |
|||||||||||
| 2004 |
2005 |
2005 |
||||||||||
| (in thousands) | ||||||||||||
| Statement of Operations Data: |
||||||||||||
| Revenues |
$ | 1,591,656 | $ | 4,335,791 | $ | 6,004,015 | ||||||
| Gross Profit: |
245,809 | 579,713 | 665,189 | |||||||||
| Depreciation and amortization |
32,793 | 76,874 | 85,534 | |||||||||
| Operating income |
106,999 | 234,904 | 275,529 | |||||||||
| Interest expense |
(25,111 | ) | (66,350 | ) | (99,631 | ) | ||||||
| Gain on Energy Transfer Transactions |
320,893 | — | — | |||||||||
| Minority interest in income from continuing operations |
(32,170 | ) | (91,439 | ) | (114,745 | ) | ||||||
| Income from continuing operations before income taxes |
371,282 | 70,047 | 58,459 | |||||||||
| Income tax expense (c) |
(3,861 | ) | (5,168 | ) | (5,776 | ) | ||||||
| Income from continuing operations |
367,421 | 64,879 | 52,683 | |||||||||
| Net income from continuing operations per share/unit |
2.10 | 0.33 | ||||||||||
| Balance Sheet Data (end of period): |
||||||||||||
| Total assets |
$ | 2,247,760 | $ | 4,522,355 | $ | 4,775,394 | ||||||
| Current liabilities |
1,018,670 | 1,015,618 | 1,015,618 | |||||||||
| Long-term debt |
698,343 | 1,570,155 | 1,870,155 | |||||||||
| Stockholders’ equity/partners’ capital |
307,619 | 423,975 | 270,444 | |||||||||
| Consolidated Historical for Energy Transfer Equity | ||||||
| For the Nine Months Ended May 31, | ||||||
| 2004 |
2005 | |||||
| (in thousands) | ||||||
| Other Financial Data: |
||||||
| EBITDA, as adjusted (unaudited)(e) |
$ | 111,715 | $ | 218,211 | ||
| Net cash provided by operating activities |
135,180 | 216,850 | ||||
| Net cash used in investing activities |
210,279 | 1,038,645 | ||||
| Net cash provided by (used in) financing activities |
86,445 | 760,550 | ||||
| (a) | We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. On January 20, 2004, we and Heritage completed a series of transactions which, among other things, included: |
| • | we contributed our subsidiary La Grange Acquisition, L.P., and its subsidiaries and affiliates who conducted business under the assumed name of Energy Transfer Company, or ETC OLP, to Heritage in exchange for cash, assumption of certain liabilities and three classes of securities; and |
| • | we acquired the general partner of Heritage from its owners. |
| We refer to these transactions as the “Energy Transfer Transactions.” The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards |
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| No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETP was the acquirer for accounting purposes. As a result, our historical financial statements are the historical financial statements of the combined company. In February 2005, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name from Energy Transfer Company, L.P. to Energy Transfer Equity, L.P. |
| (b) | On December 27, 2002, we purchased the remaining 50% of Oasis Pipe Line Company. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After that date, Oasis Pipe Line’s results of operations were consolidated with our results of operations as a wholly owned subsidiary. |
| (c) | As a partnership, we are not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings, Inc. and Heritage Service Corporation, are corporations that are subject to income taxes. Prior to 2003, Oasis Pipe Line was an equity method investment of ETC OLP, and taxes were netted against the equity method earnings. Aquila Gas Pipeline was a tax-paying corporation, and as such recognized income taxes related to its earnings in all periods presented. |
| (d) | Net income per unit is computed by dividing the limited partners’ interest in net income by the weighted average number of units outstanding. |
| (e) | EBITDA, as adjusted, is defined as our earnings before interest, taxes, depreciation (adjusted for depreciation directly attributable to minority interests), amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, gain or loss on discontinued operations (net of minority interests), gain on the Energy Transfer Transactions and other expenses. We present EBITDA, as adjusted, on a partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the common units awarded under ETP’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the gain or loss arising from our disposal of assets, discontinued operations, and the gain on the Energy Transfer Transactions are not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements. |
| EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of the partnership’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to our investors for trending, analyzing and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA, as adjusted, allows investors to view the partnership’s performance in a manner similar to the methods used by management and provides additional insight to our operating results. |
| EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full partnership basis, we add back the minority interest of the general partner because net income per limited partner unit is reported net of the |
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| general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of our business. The inclusion of these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ETP’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in the partnership’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted, since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read Note 5 to our consolidated financial statements included in this prospectus. |
| There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, our calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by us in the past. Management compensates for these limitations by considering EBITDA, as adjusted, in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities. A reconciliation of EBITDA, as adjusted, to net income (loss) is presented below. Please read “Reconciliation of EBITDA, As Adjusted, to Net Income” below. |
Reconciliation of EBITDA, as Adjusted
The following tables set forth the reconciliation of EBITDA, as adjusted, to our net income for the periods indicated:
| Historical |
Pro Forma |
||||||||||||||||||||||||
| Aquila Gas Pipeline |
Energy Transfer Equity |
||||||||||||||||||||||||
| Year Ended December 31, |
Nine Months Ended September 30, 2002 |
Eleven Months Ended August 31, 2003 |
Year Ended August 31, 2004 |
Year Ended August 31, 2004 |
|||||||||||||||||||||
| 1999 |
2000 |
2001 |
|||||||||||||||||||||||
| (in thousands) | |||||||||||||||||||||||||
| Net income |
$ | 11,589 | $ | 11,235 | $ | 25,758 | $ | 4,739 | $ | 46,235 | $ | 450,217 | $ | 24,251 | |||||||||||
| Gain on Heritage Transaction |
— | — | — | — | — | (395,253 | ) | — | |||||||||||||||||
| Depreciation and amortization |
27,061 | 30,049 | 30,779 | 22,915 | 11,870 | 56,242 | 105,676 | ||||||||||||||||||
| Interest expense |
12,894 | 12,098 | 6,858 | 3,931 | 12,453 | 41,217 | 119,709 | ||||||||||||||||||
| Income tax expense |
5,913 | 7,657 | 15,403 | (467 | ) | 4,432 | 2,792 | 5,272 | |||||||||||||||||
| Non-cash compensation expense |
— | — | — | — | — | 42 | 1,274 | ||||||||||||||||||
| Interest income and other |
— | — | — | — | (202 | ) | (516 | ) | (3,362 | ) | |||||||||||||||
| (Gain) loss on disposal of assets |
— | — | — | — | 1,006 | 1,146 | |||||||||||||||||||
| Minority interests |
— | — | — | — | — | 178 | |||||||||||||||||||
| Equity in earnings of investees |
— | — | — | — | 1,003 | ||||||||||||||||||||
| Depreciation, amortization and interest of investee |
— | — | — | — | 440 | 762 | |||||||||||||||||||
| Depreciation, amortization and interest of discontinued operations |
— | — | — | — | 1,591 | 2,249 | 2,249 | ||||||||||||||||||
| Depreciation, amortization and interest of minority interests |
— | — | — | — | — | — | (5,459 | ) | |||||||||||||||||
| EBITDA, as adjusted |
$ | 57,457 | $ | 61,039 | $ | 78,798 | $ | 31,118 | $ | 77,382 | $ | 158,436 | $ | 251,696 | |||||||||||
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of Energy Transfer Equity’s financial condition and results of operations in conjunction with the historical and pro forma consolidated financial statements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included elsewhere in this prospectus. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding some of the risks inherent in our and ETP’s businesses.
General. We are a Delaware limited partnership. In addition to directly owning approximately 33% of Energy Transfer Partners’ outstanding common units, we indirectly own and control the general partner of ETP, through which we hold the 2% general partnership interest and 50% of the incentive distribution rights in ETP. ETP is a publicly traded limited partnership that is primarily engaged in the natural gas midstream, transportation and storage business and also has a national retail propane business.
ETP has increased its quarterly distribution on its common units 16 times since its initial public offering in 1996. On September 2, 2005, ETP increased its quarterly distribution to $0.50 per unit of ETP per quarter for the quarter ended August 31, 2005 (or $2.00 per unit of ETP on an annualized basis). Under ETP’s current capital structure, a distribution of $0.50 per unit will result in a quarterly distribution to us of approximately $26.4 million, consisting of $18.2 million in respect of our ownership of ETP’s common units, $1.5 million in respect of our indirect ownership of the 2% general partner interest in ETP, and $6.7 million in respect of our indirect ownership of 50% of ETP’s incentive distribution rights. We forecast that our partnership interests in ETP will generate $105.4 million in cash to us for the fiscal year ending August 31, 2006, assuming a $2.00 per unit annual distribution.
Our primary business objective is to increase our cash distributions to our unitholders by actively assisting ETP in executing its business strategy. We intend to support ETP in implementing its business strategy by assisting ETP in identifying, evaluating, and pursuing growth opportunities. In the future, we may also support the growth of ETP through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
ETP’s primary objective is to increase the level of its cash distributions over time by pursuing a business strategy that is currently focused on growing its intrastate natural gas midstream business (including transportation, gathering, compression, treating, processing, storage and marketing) and its national propane business through, among other things, pursuing construction and expansion opportunities relating to its existing infrastructure and acquiring additional businesses or assets.
Our aggregate partnership interests in ETP consist of the following:
| • | the 2% general partner interest in ETP, which we own through our ownership interests in Energy Transfer Partners GP; |
| • | 50% of the outstanding incentive distribution rights in ETP, which we own through our ownership of equity interests in Energy Transfer Partners GP; and |
| • | approximately 36.4 million common units of ETP (including 3.64 million common units of ETP which we will purchase at the closing of the offering), all of which we hold directly. |
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The following table sets forth the distributions that we have received from ETP during the periods indicated and reflects our partnership interests, including our incentive distribution rights, as of the dates indicated after giving effect to our current structure.
| Cash Distributions Received by Us from ETP | ||||||
| Year Ended August 31, 2004 |
Nine Months 2005 | |||||
| (in thousands) | ||||||
| Distributions on ETP common units held by us |
$ | 20,411 | $ | 41,693 | ||
| Distributions from ownership interest in the ETP general partner |
1,392 | 3,062 | ||||
| Distributions from ETP incentive distribution rights |
1,811 | 8,756 | ||||
| Total |
$ | 23,614 | $ | 53,511 | ||
Factors That Significantly Affect our Results. Our only cash-generating assets currently consist of our partnership interests in ETP. Therefore, our cash flow and resulting ability to make distributions initially will be completely dependent upon the ability of ETP to make distributions in respect of those interests and rights. The actual amount of cash that ETP will have available for distribution will primarily depend on the amount of cash it generates from operations.
ETP’s results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates its midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, it receives a fee for natural gas gathering, compressing, treating or processing services. The revenue it earns from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices. The terms of its contracts vary based upon gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Many of these contracts remain in effect for several years. The contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
Results from ETP’s transportation and storage segment are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through its transportation pipelines. Under transportation contracts, ETP charges its customers (1) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay ETP even if the customer does not transport natural gas on the respective pipeline, (2) a transportation fee, which is based on the actual throughput of natural gas by the customer, or (3) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly. The transportation and storage segment also generates its revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the Houston Pipeline System.
ETP’s propane-related segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which ETP has no control. Product supply contracts are one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. In particular, ETP’s propane distribution business is largely seasonal and dependent upon weather conditions in its service areas.
In addition, the actual amount of cash that ETP will have available for distribution will fluctuate from quarter to quarter based on many additional factors, including:
| • | fluctuations in cash flow generated by ETP’s operating activities; |
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| • | the level of capital expenditures ETP makes; |
| • | the cost of capital used to fund any acquisitions; |
| • | debt service requirements; |
| • | fluctuations in working capital needs; |
| • | restrictions on distributions contained in ETP’s credit facility and senior notes; |
| • | ETP’s ability to borrow under its working capital facility to make distributions; |
| • | prevailing economic conditions; and |
| • | the amount, if any, of cash reserves established by ETP’s general partner in its discretion for the proper conduct of its business. |
Ability to Independently Pursue Opportunities. In addition to assisting ETP in identifying, evaluating and pursuing growth opportunities, we may separately pursue opportunities to acquire businesses or construct assets when, for example, these opportunities:
| • | do not fit within ETP’s then-current strategy; |
| • | arise at a time when ETP has capital constraints in its credit agreements or other reasons; or |
| • | are not economically justified for ETP at the time. |
A transaction might not be economically justified for ETP, if, for example, the expected timing of the cash flow from the project, the level of cash flow accretion during the early stages of the project or the anticipated capital costs of the project would adversely impact ETP’s ability to make cash distributions. If we pursue such a project, our results of operations and ability to make distributions to our common unitholders could be negatively impacted.
If we are successful in independently pursuing a project, we may offer to transfer or may sell the project to ETP if the project is complementary to ETP’s then-current strategy or operations. If the project is not complementary to ETP’s strategy and operations or ETP elects not to purchase the project form us, we may retain the project for further development and subsequent sale or, alternatively, sell the project to another company. The opportunities that we pursue that are not complementary to ETP’s strategy or operations may include opportunities to acquire a business or construct an asset in geographic areas where ETP does not desire to operate, or opportunities to acquire a business or construct an asset that would not be complementary with the natural gas gathering, transportation and storage or retail propane businesses of ETP.
Financial Presentation. We reflect our ownership interest in ETP on a consolidated basis, which means that our financial results are combined with ETP’s financial results and the results of our other subsidiaries. The limited partner interests in ETP not owned by affiliates of the general partner are reflected as an expense in our results of operations. We initially will have no separate operating activities apart from those conducted by ETP, and our cash flows currently consist of distributions from ETP on the partnership interests, including the incentive distribution rights, that we own. Our consolidated results of operations principally reflect the results of operations of ETP, and also include our gains on the issuance of ETP common units, provision for income taxes and interest of non-controlling partners in ETP’s net income. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the operating activities and results of operations of ETP. The historical results of our operations do not reflect the incremental expenses we expect to incur as a result of being a publicly traded partnership.
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Energy Transfer Partners is a Delaware limited partnership. ETP’s common units are listed on the New York Stock Exchange under the symbol “ETP.” ETP’s business activities are primarily conducted through its subsidiaries, La Grange Acquisition, L.P., which we refer to as “ETC OLP,” and Heritage Operating, L.P., which we refer to as “HOLP.” Energy Transfer Partners, L.P., ETC OLP and HOLP are sometimes referred to collectively in this prospectus as “ETP.”
Energy Transfer Transactions
On January 20, 2004, we and Heritage completed a series of transactions which, among other things, included:
| • | we contributed ETC OLP to Heritage in exchange for cash, the assumption of certain liabilities and three classes of securities; |
| • | we acquired the general partner of Heritage, Energy Transfer Partners GP, L.P., from its owners; and |
| • | Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”), the former general partner of Heritage, from the then-current owners of Energy Transfer Partners GP, L.P. |
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. As a result, our historical financial statements are the historical financial statements of the combined company. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage.
Other Recent ETP Transactions
ET Fuel System Acquisition. On June 2, 2004, ETP announced the closing of its acquisition of the midstream natural gas pipeline and storage system of TXU Fuel Company, a gas transportation subsidiary of TXU Corp. for approximately $500.0 million in cash, subject to post-closing adjustments. This system, which we refer to as the ET Fuel System, serves some of the most active drilling areas in the United States. The ET Fuel System is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. The ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas.
East Texas Pipeline Expansion. In June 2004, ETP completed its East Texas Pipeline expansion, which consisted of 78 miles of pipeline that connected certain third party and ETC OLP-owned treating facilities to our Southeast Texas assets. The East Texas Pipeline expansion provides initial capacity of 500 MMcf/d that can be increased to 1.0 Bcf/d. The pipeline provides producers in North Central and East Texas access to the Katy Hub. ETP currently has contracted under long-term agreements over 500 MMcf/d of pipeline capacity on the East Texas Pipeline.
Devon Midstream Assets Acquisition. On November 1, 2004, ETP announced the closing of the acquisition of certain midstream natural gas assets of Devon Energy Corporation for approximately $65.0 million in cash after adjustments. The assets, known as the Texas Chalk and Madison Systems, include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities, fractionation facilities and the 80 MMcf/d Madison gas processing plant.
Houston Pipeline System Acquisition. In January 2005, ETP acquired controlling interests in the Houston Pipeline System and related storage facilities from American Electric Power Corporation for approximately $825.0 million plus $174.0 million in natural gas inventory, subject to working capital adjustments. This
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transaction was financed by ETP through a combination of borrowings under its credit facilities and a private placement of $350.0 million of common units with institutional investors. In addition, ETP acquired working inventory of natural gas stored in the Bammel storage facility and financed it through a short-term borrowing from an affiliate. The total purchase price of approximately $825.0 million plus working capital, was allocated to the assets acquired and liabilities assumed. Under the terms of the transaction, ETP acquired all but a 2% limited partner interest in HPL Consolidation, L.P., the entity that owns the Houston Pipeline System. The Houston Pipeline System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets.
Fort Worth Basin Expansion. In May 2005, ETP completed construction of a 55-mile 24-inch natural gas pipeline in the Fort Worth Basin that connects various pipelines in north Texas and provides transportation for natural gas production from the Barnett Shale producing area. This pipeline has a capacity in excess of 400 MMcf/d. The expansion cost approximately $53.0 million, which cost was financed entirely with cash from operations.
Disposition of Elk City Gathering System. On April 14, 2005, ETP announced that it had closed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City system, to Atlas Pipeline Partners, L.P. The sale price of $190 million was used to repay a portion of the indebtedness incurred by ETP in its recent acquisition of the Houston Pipeline System and related storage facilities.
Recent Propane Acquisitions. In April 2004, ETP announced its acquisition of the assets of Edwards Propane of Marshville, North Carolina. Edwards Propane serves approximately 9,000 customers in and around the Marshville area. In July 2004, ETP announced its acquisition of the assets of Custer Gas Service, Inc., in Custer, South Dakota. Custer Gas serves approximately 1,800 customers in the Custer area. The acquisition of the assets of Boland Energy in September 2004 and of Trenton Propane in October 2004 added customer bases purchasing approximately 4.8 million gallons annually in the rural area west of St. Louis, Missouri and approximately 2.0 million gallons annually in the area north of Dallas, Texas, respectively. During the nine months ended May 31, 2005, ETP acquired substantially all of the assets of seven propane businesses.
Other Transactions. On June 20, 2005, ETP completed a private sale of 1,640,000 of its common units to a group of its senior officers. The ETP common units were sold at a price of $31.95 per ETP common unit, reflecting a discount from the closing price on the last trading day of June 17, 2005. The sale was approved by ETP’s special committee of independent directors. The ETP common units were issued pursuant to ETP’s effective shelf registration statement. Of the proceeds of approximately $52.1 million, $30.0 million was used to repay existing indebtedness and the balance was used for general partnership purposes.
On July 6, 2005, ETP announced that it had entered into a ten-year agreement with XTO Energy, Inc., pursuant to which XTO Energy agreed to transport minimum annual volumes over the ten-year term. Under the agreement, XTO Energy has the right to transport additional volumes on similar terms.
On July 26, 2005, ETP completed a private sale of 3,000,000 of its common units to an institutional investor. The ETP common units were sold at a price of $35.20 per ETP common unit. The ETP common units were issued pursuant to ETP’s effective shelf registration statement. The proceeds of approximately $105.6 million were used to retire a portion of ETP’s outstanding indebtedness under its revolving credit facility and to fund ETP’s recently announced capital expansion projects.
On July 29, 2005, ETP completed a registered exchange offer to exchange its 5.95% Senior Notes due February 1, 2015 issued in a Rule 144A private placement offering on January 18, 2005 (the “2015 Unregistered Notes”), for a like amount of 5.95% Senior Notes due February 1, 2005 that are registered under the Securities Act of 1933, as amended.
On July 29, 2005, ETP completed a Rule 144A private placement offering of 5.65% Senior Notes due 2012 (the “2012 Unregistered Notes”). The net proceeds of approximately $397.1 million were used to retire a portion
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of ETP’s outstanding indebtedness under its revolving credit facility, to fund ETP’s recently announced capital expansion projects and for general partnership purposes.
As discussed above, we have no independent operating activities apart from those conducted by ETP. Accordingly, the overview of our operations primarily reflect the operating activities of ETP.
Midstream and Transportation and Storage Segments
ETC OLP’s operations are divided into two operating segments, consisting of the midstream segment and the transportation and storage segment. ETP owns and operates approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to ETP’s gathering systems, 14 natural gas treating facilities and three natural gas storage facilities.
The midstream segment focuses on the gathering, compression, treating, processing and marketing of natural gas, and its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas.
ETP’s transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that we refer to as the ET Fuel System and certain transportation assets of the recently acquired Houston Pipeline System. Included in the recently acquired Houston Pipeline System are approximately 4,200 miles of intrastate natural gas pipeline, the Bammel natural gas storage reservoir and related transportation assets. The Houston Pipeline System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Texas Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates its midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, it receives a fee for natural gas gathering, compressing, treating or processing services. The revenue it earns from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in the midstream segment, including (1) discount-to-index price arrangements, which involve purchases of natural gas at either: (a) a percentage discount to a specified index price, (b) a specified index price less a fixed amount or (c) a percentage discount to a specified index price less an additional fixed amount; (2) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed-upon percentage of the proceeds based on an index price; and (3) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sell the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of its contracts vary based upon gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. The contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
ETP conducts its marketing operations through its producer services business, in which it markets the natural gas that flows through its assets, which we refer to as “on-system gas.” ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, which we refer to as “off-system gas.” For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply
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points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
ETP’s marketing activities involve the marketing of on-system and off-system gas. For the fiscal year ended August 31, 2004, it marketed approximately 975 MMcf/d of natural gas, 49% of which was on-system gas. Substantially all of ETP’s on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline.
For off-system gas, ETP purchases gas or acts as an agent for small independent producers that do not have marketing operations. ETP develops relationships with natural gas producers, which facilitate its purchase of their production on a long-term basis. ETP believes that this business provides it with strategic insights and valuable market intelligence, which may impact its expansion and acquisition strategy.
Results from ETP’s transportation and storage segment are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through its transportation pipelines. Under transportation contracts, ETP charges its customers (1) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay ETP even if the customer does not transport natural gas on the respective pipeline, (2) a transportation fee, which is based on the actual throughput of natural gas by the customer, or (3) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly. The transportation and storage segment also generates its revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the Houston Pipeline System.
As a result of ETP’s acquisition of the Houston Pipeline System, it now engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. The Bammel storage reservoir is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. Therefore, ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. Since the acquisition, ETP has continually managed its positions to enhance the future profitability of its storage position. ETP may, from time to time, change its scheduled injection and withdrawal plans based on market conditions and adjust the level of working natural gas stored in the Bammel reservoir. ETP expects margins from the Houston Pipeline System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure you that the expectations of ETP’s management will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which ETP operates, competitive factors in the energy industry and other issues.
Retail and Wholesale Propane Segments
ETP’s propane-related segments are operated by HOLP and its subsidiaries that are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments (the propane segments) and also through the liquids marketing activity of Heritage Energy Resources. HOLP derives its revenue primarily from the retail propane segment. We believe that ETP is the fourth largest retail marketer of propane in the United States, based on retail gallons sold. ETP serves more than 700,000 propane customers from 315 customer service locations in 34 states.
The propane segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which ETP has no control. Product supply contracts are one-year
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agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points.
ETP’s retail propane business consists principally of transporting propane purchased in the contract and spot markets, primarily from major fuel suppliers, to its customer service locations and then to propane tanks located on the customers’ premises, as well as to portable propane cylinders.
ETP’s propane distribution business is largely seasonal and dependent upon weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of Heritage’s retail propane volume and in excess of 80% of Heritage’s EBITDA, as adjusted, is attributable to sales during the six-month peak heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in the first and second fiscal quarters. However, cash flow from operations is generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak heating season. Sales to industrial and agricultural customers are much less weather sensitive. ETP uses information on normal temperatures to understand how temperatures that are colder or warmer than normal affect historical results of operations and to prepare forecasts related to its future operations.
The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. Wholesale propane segment’s margins are substantially lower than retail margins. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.
Amounts discussed below reflect 100% of the results of M-P Energy Partnership (the foreign wholesale propane segment). M-P Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest. Because M-P Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to ETP’s net income is not significant and the minority interest of this partnership is excluded from the EBITDA, as adjusted, calculation.
Analysis of Historical Results of Operations
Nine Months Ended May 31, 2005 Compared to the Nine Months Ended May 31, 2004
The Energy Transfer Transactions affect the comparability of our financial statements for the nine months ended May 31, 2005 to the nine months ended May 31, 2004 because our consolidated financial statements for the nine months ended May 31, 2004 reflect the results of ETC OLP and its subsidiaries for the full period and the results of HOLP and Heritage Holdings from January 20, 2004 through May 31, 2004 (see Note 1 to our consolidated financial statements). The changes in the line items discussed below are a result of these transactions. The aggregate results in the propane segments disclosed below reflect Heritage’s historical results for the nine months ended May 31, 2004 combined with the historical results of Energy Transfer Company for the nine months ended May 31, 2004, and are presented for comparability purposes only. This aggregate information is not (1) necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (2) a measure of performance calculated in accordance with generally accepted accounting principles.
In addition to the Energy Transfer Transactions, the acquisition of the ET Fuel System affects the comparability of the historical results of operations in ETP’s transportation and storage segment for the nine
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months ended May 31, 2005 compared to the nine months ended May 31, 2004. ETP acquired the ET Fuel System in June 2004; therefore, the results of operations for the three and nine months ended May 31, 2004 do not reflect the impact of this acquisition. ETP also acquired the Houston Pipeline System in January 2005. The acquisition of the Houston Pipeline System affects the comparability of the historical results of operations in ETP’s transportation and storage operating segment for the nine months ended May 31, 2005 compared to the nine months ended May 31, 2004. The results of operations for the nine months ended May 31, 2004 do not reflect the impact of this acquisition and the results of operations for the nine months ended May 31, 2005 only include the results of operations of the Houston Pipeline System from the date of acquisition to May 31, 2005.
In addition, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, on April 14, 2005. These results are presented as net amounts in the Consolidated Statements of Operations, with prior periods restated to conform to the current presentation. Selected operating results for the midstream segment discussed below have been restated for the periods presented to reflect the discontinued operations.
Overall Increase in Results of Operations. ETP has experienced a significant increase in its results of operations for the nine months ended May 31, 2005 when compared to the same period last year. The increase is principally attributable to the following:
| • | Energy Transfer Transactions. The Energy Transfer Transactions described above were accounted for as a reverse acquisition and ETC OLP had no propane operations prior to January 20, 2004; |
| • | Acquisitions. ETP has been successful in completing various strategic acquisitions during the last twelve to eighteen months by both of its operating partnerships, ETC OLP and HOLP. As discussed above, ETP completed the acquisition of the ET Fuel System in June 2004 and the Houston Pipeline System in January 2005. ETP also acquired the Texas Chalk and Madison System in November 2004. These acquisitions have significantly increased ETP’s asset base and operations for the 2005 periods presented. In addition, HOLP has made a number of propane acquisitions during the periods presented; |
| • | Increased Volumes and Prices. In addition to the acquisitions, ETP has also experienced increased volumes in our existing operating segments as a result of various strategies put in place by management. Commodity prices have also increased resulting in increased revenues and costs of sales, primarily in ETP’s midstream segment. |
Comparative Results for the Nine Months Ended May 31, 2005 and 2004
Volume. The following table presents selected volumetric information related to ETP’s operating segments for the nine months ended May 31, 2005 and 2004:
| Nine Months Ended | ||||
| May 31, 2005 |
May 31, 2004 | |||
| (Actual) | (Actual) | |||
| Midstream |
||||
| Natural gas MMBtu/d—sold |
1,594,780 | 982,314 | ||
| NGLs Bbls/d—sold |
13,194 | 7,375 | ||
| Transportation |
||||
| Natural gas MMBtu/d—sold |
1,660,567 | — | ||
| Natural gas MMBtu/d—transported |
3,214,842 | 905,284 | ||
| NGLs Bbls/d—sold |
2,273 | — | ||
| • | Midstream. For the nine months ended May 31, 2005 natural gas sales volumes were 1,594,780 MMBtu/d compared to 982,314 MMBtu/d for the nine months ended May 31, 2004, an increase of |
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| 612,466 MMBtu/d or 62.4%. NGLs sales volumes were 13,194 Bbls/d and 7,375 Bbls/d for nine months ended May 31, 2005 and May 31, 2004, respectively. Excluding intercompany gas sales, natural gas sales were 1,376,179 MMbtu/d. The increased natural gas sales volumes are a result of ETP’s expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counterparties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004. ETP’s sales volumes of NGLs may vary due to its ability to bypass its processing plants when conditions exist that make it less favorable to process and extract NGLs from its processing plants. NGL volumes have increased during the nine months ended May 31, 2005 compared to the same period last year principally due to favorable processing conditions and increased throughput through ETP’s processing facilities. |
| • | Transportation and Storage. For the nine months ended May 31, 2005 transportation natural gas volumes increased by 2,309,558 MMBtu/d from 905,284 MMBtu/d for the nine months ended May 31, 2004 to 3,214,842 MMBtu/d. The increase in transportation volumes is principally due to an increase in throughput volumes experienced on ETP’s Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, the completion of the East Texas Pipeline in June 2004, and additional transportation volumes from the Houston Pipeline System acquisition. The Houston Pipeline System’s natural sales volumes were 1,660,567 MMBtu for the nine months ended May 31, 2005 and processed 2,273 Bbls/d during the nine months ended May 31, 2005. |
| Nine Months Ended | ||||||
| May 31, 2005 |
May 31, 2004 |
May 31, 2004 | ||||
| (Actual) | (Actual) | (Aggregate) | ||||
| Propane gallons |
||||||
| (in thousands) |
||||||
| Retail |
346,156 | 166,099 | 337,751 | |||
| Domestic wholesale |
9,414 | 3,824 | 9,205 | |||
| Foreign wholesale |
50,293 | 22,337 | 45,636 | |||
| • | Retail Propane. For the nine months ended May 31, 2005 total retail propane gallons sold were 346.1 million gallons, compared to 166.1 million retail propane gallons reflected in the nine months ended May 31, 2004. The difference in retail gallons sold is partially due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting and ETC OLP had no propane operations prior to the Energy Transfer Transactions. |
As a comparison, ETP would have reflected an aggregate of 337.8 million retail gallons if the Energy Transfer Transactions would have occurred at the beginning of fiscal year 2004. The aggregate increase is due to a 20.3 million gallon increase resulting from volumes sold by customer services locations added through acquisitions, offset by a 12.0 million gallon decline in volumes sold due in part to warmer weather. ETP experienced temperatures that were 6.6% warmer than normal and 0.3% warmer than last year for the nine month period. We believe ETP’s volumes for the three and nine months ended May 31, 2005 are being negatively impacted by the conservation efforts of its customers in reaction to record high energy prices. ETP has increased its marketing efforts to attain new customers, which partially offsets the negative factors described above.
| • | Domestic Wholesale Propane. For the nine months ended May 31, 2005 ETP sold 9.4 million domestic wholesale propane gallons as compared to 3.8 million in the nine months ended May 31, 2004. As a comparison, ETP would have reflected aggregate volumes of 9.2 million gallons for the nine months ended May 31, 2004. Of the 0.2 million gallon aggregate increase in domestic wholesale propane gallons, 0.8 million is primarily due to customers added from an acquisition in December 2003, offset by a decrease of 0.6 million gallons related to warmer weather. |
| • | Foreign Wholesale Propane. For the nine months ended May 31, 2005 ETP sold 50.3 million foreign wholesale propane gallons as compared to 22.3 million gallons for the nine months ended May 31, |
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| 2004. As a comparison, ETP would have reflected aggregate volumes of 45.6 million foreign wholesale propane gallons for the nine months ended May 31, 2004. The 4.7 million gallon aggregate increase in foreign gallons sold is due to increased marketing efforts in ETP’s foreign markets partially offset by warmer weather for the nine months ended May 31, 2005 compared to the nine months ended May 31, 2004. |
Consolidated Results
| Nine Months Ended May 31, |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| (unaudited) | ||||||||
| (in thousands) | ||||||||
| Consolidated Information: |
||||||||
| Revenues |
$ | 4,335,791 | $ | 1,591,656 | ||||
| Cost of sales |
3,756,078 | 1,345,847 | ||||||
| Gross margin |
579,713 | 245,809 | ||||||
| Operating expenses |
224,122 | 86,622 | ||||||
| Selling, general and administrative |
43,813 | 19,395 | ||||||
| Depreciation and amortization |
76,874 | 32,793 | ||||||
| Consolidated operating income |
234,904 | 106,999 | ||||||
| Equity (losses) in earnings of affiliates |
(161 | ) | 506 | |||||
| Interest expense |
(66,350 | ) | (25,111 | ) | ||||
| Loss on extinguishment of debt |
(6,550 | ) | — | |||||
| Loss on disposal of assets |
(665 | ) | (235 | ) | ||||
| Gain on Energy Transfer Transactions |
— | 320,893 | ||||||
| Other, net |
308 | 400 | ||||||
| Minority interest in income from continuing operations |
(91,439 | ) | (32,170 | ) | ||||
| Income tax expense |
(5,168 | ) | (3,861 | ) | ||||
| Income from continuing operations |
64,879 | 367,421 | ||||||
| Income from discontinued operations |
5,498 | 4,129 | ||||||
| Income from sale of discontinued operations, net of income tax expense |
104,562 | — | ||||||
| Minority interest in income from discontinued operations |
(53,060 | ) | (1,776 | ) | ||||
| Total income from discontinued operations |
57,000 | 2,353 | ||||||
| Net income |
$ | 121,879 | $ | 369,774 | ||||
Equity in Earnings (Losses) of Affiliates. Equity in earnings (losses) of affiliates was $(0.2) million for the nine months ended May 31, 2005, compared to $0.5 million for the nine months ended May 31, 2004. In connection with the Houston Pipeline System acquisition, ETP acquired a 50% interest in an unconsolidated affiliate. ETP’s share of losses from this affiliate was $(0.4) million for the nine months ended May 31, 2005.
Interest Expense. For the nine months ended May 31, 2005 interest expense was $66.3 million as compared to $25.1 million for the nine months ended May 31, 2004, an increase of $41.2 million. Of this increase, $25.0 million is the result of the borrowings on the 2015 Unregistered Notes and the ETP Revolving Credit Facility. Approximately $10.5 million of the increase is interest on HOLP’s debt that is not reflected for the full nine months ended May 31, 2004. $1.0 million is related to the increase in our short-term borrowings for the acquisition of working inventory of natural gas in connection with the Houston Pipeline System acquisition. The remaining $4.7 million is the result of additional interest in ETP’s midstream and transportation and storage segments due to the Energy Transfer Transactions and the acquisition of the ET Fuel System in June 2004. This increase includes interest expense of $9.5 million in deferred financing costs related to the Energy Transfer
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Transactions, the Houston Pipeline System acquisition, and the ET Fuel System acquisition, which ETP was amortizing on a straight-line basis over the remaining term of the related credit facility prior to the debt refinancing in January 2005.
Loss on extinguishment of debt. As a result of refinancing certain debt during the nine months ended May 31, 2005, ETP wrote off $6.5 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of the 2015 Unregistered Notes. The write-off was accounted for as a loss on extinguishment of debt.
Gain on Energy Transfer Transactions. In accordance with EITF 90-13 and SFAS 141, we recorded a gain of $320.9 million during the nine months ended May 31, 2004 as a result of the Energy Transfer Transactions. The total gain recorded was increased to the extent that distributions received by us from ETC OLP in the transactions exceeded our investment in ETC OLP prior to the transactions.
Income Tax Expense. Income tax expense was $5.2 million for the nine months ended May 31, 2005 as compared to $3.8 million for the nine months ended May 31, 2004. As a partnership, ETP is not subject to income taxes. However, Oasis Pipe Line Company, Heritage Service Company, and Heritage Holdings, our wholly owned subsidiaries of ETP, are corporations that are subject to income taxes. The increase in income tax expense is due to (1) income tax expense recorded in Heritage Holdings for the entire period in the nine months ended May 31, 2005 as compared with 2004 when tax expense related to Heritage Holdings was only included in ETP’s results of operations after the Energy Transfer Transactions and (2) increased income from acquisitions, partially offset by lower taxes on the Oasis Pipeline due to lower taxable income for that entity.
Income from continuing operations. Income from continuing operations for the nine months ended May 31, 2005 was $64.9 million, as compared to income from continuing operations of $367.4 million for the nine months ended May 31, 2004. The decrease from the 2004 period to the 2005 period is principally due to the gain on the Energy Transfer Transactions recorded in the nine-month period ended May 31, 2004 that was not present in income for the nine months ended May 31, 2005.
Minority interest expense from continuing operations. Minority interest expense from continuing operations was $91.4 million for the nine months ended May 31, 2005 compared to $32.2 million for the nine months ended May 31, 2004. The increase of $59.2 million is related to the increases in the income from continuing operations reported ETP of $160.1 million for the nine months ended May 31, 2005 compared to $82.1 million for the nine months ended May 31, 2004. The minority interest from continuing operations for the nine months ended May 31, 2004 was not affected by the gain on the Energy Transfer Transactions because this gain was entirely attributable to ETE prior to the Energy Transfer Transactions.
Income from discontinued operations. On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191.6 million, including certain adjustments as defined in the purchase and sale agreement.
Revenues from the Elk City System were $105.5 million for the nine months ended May 31, 2005 as compared to $94.8 million for the nine months ended May 31, 2004. Costs and expenses were $100.0 for the nine months ended May 31, 2005 and $90.7 for the same period last year. Income from discontinued operations before minority interest expense for the nine months ended May 31, 2005 and 2004 was $5.5 million and $4.1 million, respectively. The increase in revenues, expenses and income was primarily due to increased throughput volumes and sales prices. In addition, ETP experienced increased margins during the nine months ended May 31, 2005 as compared to the same period last year due to favorable processing conditions. The gain on the sale of the Elk City System was $104.6 million with related income tax expense of $1.9 million recorded by Heritage Holdings, Inc.
Minority interest expense from discontinued operations. Minority interest expense from discontinued operations was $53.1 million for the nine months ended May 31, 2005 compared to $1.8 million for the nine
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months ended May 31, 2004. Of the increase of $88.8 million, $87.2 million was related to the gain on the sale of discontinued operations. The remaining increase of $1.7 million is due to the increase in income from discontinued operations.
Net Income. We reflected net income of $121.9 for the nine months ended May 31, 2005, as compared to $369.8 million for the nine months ended May 31, 2004. Of the decrease of $247.9 million, $320.9 million is due to the gain on the Energy Transfer Transactions recorded in the nine-month period ended May 31, 2004 that was not present in income for the nine months ended May 31, 2005. The remaining increase is primary acquisition-related income, attributed to these increases in ETP’s operating segments for the nine months. The effect of the Energy Transactions described above also attributed to the increase for the nine months ended May 31, 2005 as compared to May 31, 2004.
EBITDA, as adjusted. For the nine months ended May 31, 2005 EBITDA, as adjusted, increased $106.5 million to $218.2 million as compared to EBITDA, as adjusted, of $111.7 million for the nine months ended May 31, 2004. This increase is due to the Energy Transfer Transactions and the operating results of ETP’s segments described below. Aggregate EBITDA, as adjusted, would have been $164.6 million for the nine months ended May 31, 2004.
EBITDA, as adjusted, is computed as follows:
| Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| (unaudited) | ||||||||
| (in thousands) | ||||||||
| Net income reconciliation |
||||||||
| Net income |
$ | 121,879 | $ | 369,774 | ||||
| Gain on the Energy Transfer Transactions |
(320,893 | ) | ||||||
| Gain on sale of discontinued operations, net of income tax expense |
(104,562 | ) | — | |||||
| Minority interest expense on sale of discontinued operations |
49,686 | — | ||||||
| Depreciation and amortization |
76,874 | 32,793 | ||||||
| Interest expense |
66,350 | 25,111 | ||||||
| Income tax expense on continuing operations |
5,168 | 3,861 | ||||||
| Non-cash compensation expense |
1,206 | — | ||||||
| Other (income) expense, net |
(67 | ) | (400 | ) | ||||
| Depreciation, amortization, and interest of investee |
493 | 316 | ||||||
| Depreciation, amortization, and interest of discontinued operations |
1,547 | 918 | ||||||
| Depreciation related to minority interest |
(7,578 | ) | — | |||||
| Loss on extinguishment of debt |
6,550 | — | ||||||
| Loss on disposal of assets |
665 | 235 | ||||||
| EBITDA, as adjusted (a) |
$ | 218,211 | $ | 111,715 | ||||
| Heritage EBITDA, as adjusted (b) |
$ | 52,845 | ||||||
| Aggregate EBITDA, as adjusted (b) |
$ | 164,560 | ||||||
| (a) | EBITDA, as adjusted, is defined as our earnings before interest, taxes, depreciation (adjusted for depreciation directly attributable to minority interests), amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, gain or loss on discontinued operations (net of minority interests), gain on the Energy Transfer Transactions and other expenses. We present EBITDA, as adjusted, on a partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the common units of ETP awarded under ETP’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the |
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| gain or loss arising from our disposal of assets, discontinued operations, and the gain on the Energy Transfer Transaction are not included when determining EBITDA as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in ETP’s consolidated financial statements. |
| EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of ETE’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of ETP’s ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to ETE’s investors for trending, analyzing and benchmarking the operating results of ETE from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA, as adjusted, allows investors to view ETE’s performance in a manner similar to the methods used by management and provides additional insight to ETP’s operating results. |
| EBITDA, as adjusted, is used by management to determine ETP’s operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of ETP’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. ETP has a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full partnership basis, we add back the minority interest of the general partner because net income per limited partner unit is reported net of the general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense of ETP which is a non-cash expense item resulting from its unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the its business. The inclusion of these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare ETE’s operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ETP’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in ETE’s operating results but are not classified in interest, depreciation and amortization. We do not include gain or loss on the sale of assets when determining EBITDA, as adjusted, since including non-cash income or loss resulting from the sale of assets increases/decreases the performance measure in a manner that is not related to the true operating results of our business. In addition, ETP’s debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “—Debt Obligations—Energy Transfer Partners.” |
| There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, ETE’s calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by ETP and Heritage in the past. Management compensates for these limitations by considering EBITDA, as adjusted in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities. |
| (b) | The business combination of Energy Transfer Company and Heritage, on January 20, 2004, resulted in a change of control for accounting purposes, causing Energy Transfer’s financial statements to become those |
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| of the registrant. Because of the accounting treatment applied in the Energy Transfer Transaction, the reported first quarter fiscal 2004 actual results reflect the operations of Energy Transfer’s midstream and transportation businesses for the entire reporting period but not Heritage’s propane business for that period. The aggregate results disclosed reflect Heritage’s historical results for the period from September 1, 2003 to January 19, 2004 combined with the historical results of Energy Transfer Company for the nine months ended May 31, 2004, and is presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles. |
The following reconciliation of Aggregate EBITDA, as adjusted, to net income is presented for comparability purposes only, and is comprised of the aggregate of Energy Transfer Company and Heritage’s historical results for the periods presented.
| For the Period From January 19, 2004 |
Nine Months Ended May 31, 2004 |
||||||
| (Heritage) | (Aggregate) | ||||||
| (in thousands) | |||||||
| Net income reconciliation | |||||||
| Net income |
$ | 22,644 | $ | 392,418 | |||
| Gain on the Energy Transfer Transactions |
(320,893 | ) | |||||
| Depreciation and amortization |
15,389 | 48,182 | |||||
| Interest expense |
12,754 | 37,865 | |||||
| Income tax expense on continuing operations |
20 | 3,881 | |||||
| Non-cash compensation expense |
1,232 | 1,232 | |||||
| Other (income) expense, net |
66 | (334 | ) | ||||
| Depreciation, amortization, and interest of investee |
322 | 638 | |||||
| Depreciation, amortization, and interest of discontinued operations |
— | 918 | |||||
| Minority interests in Operating Partnership |
178 | 178 | |||||
| (Gain) loss on disposal of assets |
240 | 475 | |||||
| Heritage EBITDA, as adjusted (b) |
$ | 52,845 | |||||
| Aggregate EBITDA, as adjusted (b) |
$ | 164,560 | |||||
Nine Month Operating Results by Segment
Midstream Segment
| Nine Months Ended | ||||||
| May 31, 2005 |
May 31, 2004 | |||||
| (Actual) | (Actual) | |||||
| (in thousands) | ||||||
| Revenues |
$ | 2,676,611 | $ | 1,277,349 | ||
| Cost of sales |
2,592,209 | 1,208,986 | ||||
| Gross Margin |
84,402 | 68,363 | ||||
| Operating expenses |
15,006 | 9,347 | ||||
| Selling, general and administrative |
7,690 | 7,162 | ||||
| Depreciation and amortization |
12,573 | 8,895 | ||||
| Segment operating income |
$ | 49,133 | $ | 42,959 | ||
Gross Margin. For the nine months ended May 31, 2005, Midstream gross margin was $84.4 million as compared to $68.4 million for the nine months ended May 31, 2004, an increase of $16.0 million or 23.5%. The
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increase is principally attributable to the acquisition of the Texas Chalk and Madison Systems in November 2004 and increased throughput volumes generated by ETP’s producer services business. In addition, the increase in natural gas sales volumes has increased revenue from ETP’s fee-based arrangements. Fees from these arrangements were $38.4 million for the nine months ended May 31, 2005 as compared to $11.8 million for the same period last year. Due to a change in ETP’s contract mix during the three months ended May 31, 2005, we expect fee-based revenue to increase. However, we do not expect this change to have a significant effect in ETP’s overall gross margin.
Operating Expenses. For the nine months ended May 31, 2005, Midstream operating expenses increased $5.7 million to $15.0 million from $9.3 million for the same period last year. The increase was principally due to $2.0 million in increased compressor and pipeline maintenance, $1.2 million in increased measurement expenses, $0.6 million in increased property taxes, and $1.9 million in the aggregate, of other operating expenses primarily due to the Texas Chalk and Madison Systems’ acquisition and increased costs to operate ETP’s existing systems.
Selling, General and Administrative Expenses. Midstream general and administrative expenses increased from $7.2 million for the nine months ended May 31, 2004 to $7.7 million for the nine months ended May 31, 2005. The increase was principally due to increases of $5.7 million in employee-related expenses such as salary, incentive compensation and health care cost, and $0.4 million in transitional service fees related to the Texas Chalk and Madison Systems’ acquisition in November 2004. These increases were offset by $5.7 million in certain departmental costs allocated to the transportation and storage operating segment.
Depreciation and Amortization. For the nine months ended May 31, 2005, Midstream depreciation and amortization was $12.6 million compared to $8.9 million for the nine months ended May 31, 2004, an increase of $3.7 million or 41.6%. The increase was principally due to the Texas Chalk and Madison Systems’ acquisition in November 2004.
Transportation and Storage Segment
| Nine Months Ended | ||||||
| May 31, 2005 |
May 31, 2004 | |||||
| (Actual) | ||||||
| (in thousands) | ||||||
| Transportation and Storage Segment: |
||||||
| Revenues |
$ | 1,460,303 | $ | 58,509 | ||
| Cost of sales |
1,230,366 | 7,013 | ||||
| Gross margin |
229,937 | 51,496 | ||||
| Operating expenses |
70,941 | 13,493 | ||||
| Selling, general and administrative |
17,159 | 6,003 | ||||
| Depreciation and amortization |
24,347 | 6,618 | ||||
| Segment operating income |
$ | 117,490 | $ | 25,382 | ||
Gross margin. For the nine months ended May 31, 2005, transportation and storage gross margin was $229.9 million as compared to $51.5 million for the nine months ended May 31, 2004, an increase of $178.4 million. The increase in transportation revenues is principally due to the following:
| • | Increased Volumes on ETP’s Oasis Pipeline. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy Hub and ETP’s strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. Additionally, the differential between the Waha Hub and Katy Hub increased $0.024 from $0.256 for the nine months ended May 31, 2004 to $0.28 for the nine months ended May 31, 2005, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable. |
| • | ET Fuel System acquisition in June 2004. In connection with ETP’s acquisition of the ET Fuel |
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| System, ETP entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. ETP also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005 ETP was entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, ETP recognized an additional $14.7 million in fees during the nine months ended May 31, 2005. TXU Shipper has notified us that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006. |
| • | East Texas System. ETP completed the East Texas System in June 2004. As a result of certain changes ETP intends to implement to improve the system, we expect margins to increase in the latter half of ETP’s fiscal year. |
| • | The Houston Pipeline System acquired in January 2005. As discussed above, we expect significant fluctuations in ETP’s margins from period to period on the Houston Pipeline System due to the timing of injections and withdrawals of working natural gas. |
Operating Expenses. For the nine months ended May 31, 2005, transportation and storage operating expenses were $70.9 million as compared to $13.5 million for the nine months ended May 31, 2004, an increase of $57.4 million. The increase was principally attributable to $25.7 million in operating expenses related to the ET Fuel System that was acquired in June 2004, $7.8 million in operating expenses related to the East Texas Pipeline that was completed in June 2004, an increase of $4.7 million in operating expenses related to the Oasis Pipeline principally due to increased gas consumption to transport natural gas through its pipelines, $18.3 million in operating expenses related to the Houston Pipeline System acquisition, and $0.9 million in other operating expenses.
Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $11.2 million to $17.2 million for the nine months ended May 31, 2005 from $6.0 million for the same period last year. The increase was principally due to $5.0 million in general and administrative expenses related to the Houston Pipeline System acquisition, $1.4 million in general and administrative expenses relating to the ET Fuel acquisition, and $5.8 million related to certain department costs allocated from the midstream segment offset by a $1.0 million decrease in legal fees related to a lawsuit that was settled in January 2004 and other expenses.
Depreciation and Amortization. For the nine months ended May 31, 2005, transportation and storage depreciation and amortization increased $17.7 million from $6.6 million for the nine months ended May 31, 2004 to $24.3 million. The increase was principally attributable to the acquisitions of the ET Fuel System and the Houston Pipeline System during the 2005 fiscal period and the completion of the East Texas Pipeline in June 2004.
Retail Propane Segment
| Nine Months Ended May 31, | |||||||||
| 2005 |
2004 |
2004 | |||||||
| (Actual) | (Actual) | (Aggregate) | |||||||
| (in thousands) | |||||||||
| Retail propane revenues |
$ | 547,017 | $ | 235,383 | $ | 456,842 | |||
| Other propane-related revenues |
52,224 | 19,899 | 47,417 | ||||||
| Retail propane cost of sales |
326,120 | 127,408 | 248,845 | ||||||
| Other propane-related cost of sales |
15,009 | 5,390 | 13,300 | ||||||
| Operating expenses |
132,816 | 61,154 | 121,272 | ||||||
| Selling, general and administrative |
8,347 | 4,308 | 12,650 | ||||||
| Depreciation and amortization |
39,135 | 16,920 | 31,433 | ||||||
| Segment operating income |
$ | 77,814 | $ | 40,102 | $ | 76,759 | |||
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Revenues. For the nine months ended May 31, 2005, ETP had retail propane revenues of $547.0 million as compared to retail propane revenues of $235.4 million for the nine months ended May 31, 2004, due in part to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations. As a comparison, for the nine months ended May 31, 2004, aggregate retail propane revenues would have been $456.8 million. Of the $90.2 million aggregate increase, $32.0 million is due to the increase in volumes sold by customer service locations added through acquisitions, $76.9 million is due to higher selling prices which were a result of higher fuel costs that ETP has passed to its consumer base; offset by a decrease of $18.7 million due to the adverse impact weather related volumes and customer conservation efforts described above. ETP had other propane-related revenues of $52.2 million for the nine months ended May 31, 2005 compared to $19.9 for the nine months ended May 31, 2004. As a comparison, aggregate other propane-related revenues would have been $47.4 million for the nine months ended May 31, 2004. The aggregate increase of $4.8 million in the nine months ended May 31, 2005 compared to the nine months ended May 31, 2004 is primarily due to other propane revenue of companies acquired during the nine months ended May 31, 2005 and higher cost of propane-related resale items which ETP has recovered through an increase to its selling prices.
Costs of Sales. For the nine months ended May 31, 2005, ETP had retail propane cost of sales of $326.1 million with retail propane cost of sales of $127.4 million for the nine months ended May 31, 2004. As a comparison, for the nine months ended May 31, 2004, aggregate retail propane cost of sales would have been $248.8 million. Of the $77.3 million aggregate increase for the nine months ended May 31, 2005 as compared to the nine months ended May 31, 2004, $69.4 million reflects the increase due to higher cost of fuel, and $7.9 million due to the increase in volumes described above. ETP had other propane-related cost of sales of $15.0 million for the nine months ended May 31, 2005 as compared to $5.4 million for the nine months ended May 31, 2004. As a comparison, ETP had aggregate other propane-related cost of sales of $13.3 million. The aggregate increase in the nine months ended May 31, 2005 as compared to the nine months ended May 31, 2004 is primarily due to acquisition related cost of sales for during the nine months ended May 31, 2005 and higher cost of resale items.
Operating Expenses. For the nine months ended May 31, 2005, operating expenses for the retail propane segment were $132.8 million and $61.2 million for the nine months ended May 31, 2004. As a comparison, aggregate retail propane operating expenses would have been $121.3 million for the nine months ended May 31, 2004, or an aggregate increase of $11.5 million. Of this aggregate increase, approximately $5.7 million related to employee related expenses due to an increase in ETP’s employee base from acquisitions, $2.2 million is due to higher fuel costs to run ETP’s vehicle and other vehicle expenses, and the remaining $3.6 million is primarily due to general increase in other expenses also from acquisitions.
Selling, General and Administrative Expenses. For the nine months ended May 31, 2005, selling, general and administrative expenses for ETP’s retail propane segment were $8.3 million as compared to aggregate retail propane selling, general and administrative expenses of $12.7 for the nine months ended May 31, 2004. The aggregate selling, general and administrative expenses for the nine months ending May 31, 2004 included approximately $4.5 million in transaction costs associated with the Energy Transfer Transactions.
Depreciation and Amortization. For the nine months ended May 31, 2005, depreciation and amortization in ETP’s retail propane segment was $39.1 million as compared $16.9 million for the nine months ended May 31, 2004. ETP would have had aggregate depreciation and amortization of $31.4 million for the nine months ended May 31, 2004. The aggregate increase of $7.7 million is due primarily to the increase in depreciation of assets and amortization of intangible assets added through acquisitions and the additional depreciation and amortization of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.
Operating Income. For the nine months ended May 31, 2005, ETP had retail propane operating income of $77.8 million as compared to operating income of $40.1 million for the nine months ended May 31, 2004. Aggregate total operating income for the nine months ended May 31, 2004 was $76.8 million. These increases are primarily due to changes in revenues and expenses described above.
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Domestic Wholesale Propane Segment
| Nine Months Ended |
||||||||||||
| May 31, 2005 |
May 31, 2004 |
May 31, 2004 |
||||||||||
| (Actual) | (Actual) | (Aggregate) | ||||||||||
| (in thousands) | ||||||||||||
| Domestic Wholesale Propane Segment: |
||||||||||||
| Revenues |
$ | 10,466 | $ | 3,163 | $ | 7,199 | ||||||
| Cost of sales |
9,493 | 2,681 | 6,284 | |||||||||
| Operating expenses |
2,361 | 1,123 | 2,099 | |||||||||
| Depreciation and amortization |
514 | 249 | 433 | |||||||||
| Segment operating loss |
$ | (1,902 | ) | $ | (890 | ) | $ | (1,617 | ) | |||
Revenues. For the nine months ended May 31, 2005, domestic wholesale propane revenues were $10.5 million, compared to $3.2 million for the nine months ended May 31, 2004. Aggregate domestic wholesale propane revenues were $7.2 million for the nine months ended May 31, 2004. Of the aggregate increase of $3.3 million, $0.9 million is due to the increase in gallons due to acquisitions, and a $3.0 million is related to higher selling prices, offset by the decrease of $0.6 million due to weather related gallons described above.
Costs of Sales. For the nine months ended May 31, 2005, domestic wholesale propane cost of sales was $9.5 million and $2.7 million for the nine months ended May 31, 2004. As a comparison, aggregate domestic wholesale propane cost of sales would have been $6.3 million for the nine months ended May 31, 2004. The aggregate increase of $3.2 million is due to a $3.0 million increase from higher selling prices, and $0.2 due to the increase in volumes added from acquisitions.
Operating Expenses. For the nine months ended May 31, 2005, operating expenses for the domestic wholesale propane segment were $2.4 million and $1.1 million for the nine months ended May 31, 2004. As a comparison, ETP had aggregate domestic wholesale propane operating expenses of $2.1 million for the nine months ended May 31, 2004, or an increase of $0.3 million.
Depreciation and Amortization. For the nine months ended May 31, 2005, depreciation and amortization in ETP’s domestic wholesale propane segments was $0.5 million as compared to aggregate depreciation of $0.4 million for the nine months ended May 31, 2004. The aggregate increase of $0.1 million is due primarily to the increase in depreciation of assets added through acquisitions.
Operating Loss. For the nine months ended May 31, 2005, ETP had domestic wholesale propane operating loss of $1.9 million as compared to operating loss of $0.9 million for the nine months ended May 31, 2004. Aggregate total operating loss for the nine months ended May 31, 2004 would have been $1.6 million.
Foreign Wholesale Propane Segment
| Nine Months Ended | |||||||||
| May 31, 2005 |
May 31, 2004 |
May 31, 2004 | |||||||
| (Actual) | (Actual) | (Aggregate) | |||||||
| (in thousands) | |||||||||
| Foreign Wholesale Segment: |
|||||||||
| Revenues |
$ | 47,514 | $ | 16,758 | $ | 33,318 | |||
| Cost of sales |
44,838 | 15,560 | 30,496 | ||||||
| Selling, general and administrative |
1,255 | 544 | 1,305 | ||||||
| Depreciation and amortization |
20 | 9 | 19 | ||||||
| Segment operating income |
$ | 1,401 | $ | 645 | $ | 1,498 | |||
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Revenues. For the nine months ended May 31, 2005, foreign wholesale propane revenues were $47.5 million and $16.8 million for the nine months ended May 31, 2004. Aggregate foreign wholesale propane revenues would have been $33.3 million for the nine months ended May 31, 2004. The increase over aggregate of $14.2 million in the nine months ended May 31, 2005 is due to a $9.8 million increase related to higher selling prices and $4.4 million increase in volumes described above.
Costs of Sales. For the nine months ended May 31, 2005, foreign wholesale propane cost of sales was $44.8 million and $15.6 million for the nine months ended May 31, 2004. Aggregate foreign wholesale propane cost of sales would have been $30.5 million for the nine months ended May 31, 2004. Of the $14.3 million increase over aggregate in foreign wholesale cost of sales, $10.2 million is related to higher selling prices and $4.1 million due to volume increases described above.
Selling, General and Administrative Expenses. For the nine months ended May 31, 2005, ETP’s foreign propane segment selling, general and administrative expenses were $1.2 million as compared to $0.5 million for the nine months ended May 31, 2004. As a comparison, aggregate selling, general and administrative expenses would have been $1.3 million for the nine months ended May 31, 2004.
Operating Income. For the nine months ended May 31, 2005, ETP had foreign wholesale propane operating income of $1.4 million as compared to operating income of $0.6 million for the nine months ended May 31, 2004. Aggregate total operating income for the nine months ended May 31, 2004 would have been $1.5 million.
Other
| Nine Months Ended | |||||||||
| May 31, 2005 |
May 31, 2004 |
May 31, 2004 | |||||||
| (Actual) | (Actual) | (Aggregate) | |||||||
| (in thousands) | |||||||||
| Other |
|||||||||
| Revenue |
$ | 4,840 | $ | 2,277 | $ | 4,096 | |||
| Cost of sales |
1,227 | 490 | 933 | ||||||
| Operating expenses |
2,998 | 1,505 | 2,887 | ||||||
| Depreciation and amortization |
285 | 103 | 244 | ||||||
| Other operating income |
$ | 330 | $ | 179 | $ | 32 | |||
| Unallocated selling, general and administrative expenses |
$ | 9,362 | $ | 1,378 | $ | 2,611 | |||
Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that related to the general operations of ETP are not allocated to ETP’s segments.
For the nine months ended May 31, 2005, the total unallocated selling, general, and administrative expenses were $9.4 million as compared to $1.4 million unallocated selling, general, and administrative expense for the nine months ended May 31, 2004. Aggregate total unallocated selling, general, and administrative expense for the nine months ended May 31, 2004 would have been $2.6 million. The aggregate increase of $6.8 million increase in unallocated selling, general, and administrative expenses is due to a $3.6 million increase in professional fees, of which $1.6 million related to ETP’s ongoing efforts to comply with the Sarbanes-Oxley Act, and the remaining increase is related primarily to the general operations of ETP after the Energy Transfer Transactions.
Fiscal Year Ended August 31, 2004 Compared to the Eleven Months Ended August 31, 2003
The Energy Transfer Transactions affect the comparability of our financial statements for the fiscal year ended August 31, 2004 to the eleven months ended August 31, 2003 because our consolidated financial statements for the fiscal year ended August 31, 2004 include the twelve month results for ETC OLP and its
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subsidiaries and the results of HOLP, its subsidiaries, and Heritage Holdings only for the period from January 20, 2004 through August 31, 2004. The financial statements of ETC OLP for the eleven months ended August 31, 2003 reflect only the results of ETC OLP and its subsidiaries, and the financial statements of Heritage reflect the results of HOLP and its subsidiaries. The changes in the line items discussed below are a result of these transactions. The aggregate results disclosed below reflect Heritage’s historical results from September 1, 2003 until the closing of the Energy Transfer Transactions on January 19, 2004, Heritage’s historical results for the fiscal year ended August 31, 2003, and the actual results for the year ended August 31, 2004, for comparability purposes only. This aggregate information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
Volume. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by ETP’s midstream, transportation, retail propane, domestic wholesale propane, and foreign wholesale propane segments for the fiscal year ended August 31, 2004 and eleven months ended August 31, 2003 are as follows:
| Eleven Months August 31, 2003 |
Year Ended August 31, 2003 |
Year Ended August 31, 2004 |
Year Ended August 31, 2004 | |||||
| (ETC OLP actual) |
(Aggregate— unaudited) |
(Actual) |
(Aggregate— unaudited) | |||||
| Midstream |
||||||||
| Natural gas MMBtu/d |
490,000 | 490,000 | 934,000 | 934,000 | ||||
| NGLs bbls/d |
9,000 | 9,000 | 7,000 | 7,000 | ||||
| Transportation |
||||||||
| Natural gas MMBtu/d |
921,000 | 921,000 | 1,091,000 | 1,091,000 | ||||
| Propane gallons |
||||||||
| (in thousands) |
||||||||
| Retail |
— | 375,939 | 226,209 | 397,862 | ||||
| Domestic wholesale |
— | 15,343 | 7,071 | 12,452 | ||||
| Foreign wholesale |
— | 58,958 | 28,648 | 51,947 | ||||
| Total gallons |
— | 450,240 | 261,928 | 462,261 | ||||
Natural gas sales volumes were 934,000 MMBtu/d for the year ended August 31, 2004 compared to 490,000 MMBtu/d for the eleven months ended August 31, 2003, an increase of 444,000 MMBtu/d or 90.6%. NGLs sales volumes decreased 22.2% from 9,000 Bbls/d for the eleven months ended August 31, 2003 to 7000 Bbls/d for the year ended August 31, 2004. The increased natural gas sales volumes are a result of ETP’s expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. As previously discussed, ETP’s sales volumes of NGLs vary due to its ability to bypass its processing plants during unfavorable conditions to process and extract NGLs from its processing plants. The decrease in NGLs sales volumes was attributable to the bypassing of its La Grange plant.
Total retail propane gallons sold in the twelve months ended August 31, 2004 were 226.2 million gallons, with no retail propane gallons reflected in the year ended August 31, 2003. The difference in retail gallons sold is due to the Energy Transfer Transactions described above. ETP also sold approximately 7.1 million and 28.6 million domestic and foreign wholesale propane gallons, respectively, in the fiscal year ended August 31, 2004, with no domestic or foreign wholesale propane gallons reflected in the eleven months ended August 31, 2003. As a comparison, Heritage would have reflected aggregate volumes of 397.9 million retail propane gallons for the fiscal year ended August 31, 2004 and historical volumes of 376.0 million gallons for the fiscal year ended August 31, 2003. Of the 21.9 million gallon aggregate increase, 27.8 million gallons are the result of volumes sold by customer service locations added through acquisitions, offset by a decrease of 5.9 million gallons that were weather related. ETP experienced temperatures that were, on average, 2.73% warmer in the twelve months
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ended August 31, 2004 compared to last year and 6.47% warmer than normal during fiscal 2004. Also, as a comparison, Heritage would have reflected aggregated volumes of 12.5 million and 52.0 million domestic wholesale and foreign wholesale propane gallons, respectively, for the fiscal year ended August 31, 2004 as compared to historical volumes of 15.3 million and 59.0 million domestic and foreign wholesale propane gallons for the fiscal year ended August 31, 2003. The 2.8 million gallon decrease in domestic wholesale propane gallons is primarily due to the loss of two commercial customers to alternative fuel sources, and the 7.0 million gallon decrease in foreign wholesale volumes is due to an exchange contract that was in effect during the fiscal year ended August 31, 2003, which was not economical to renew during fiscal 2004.
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Set forth in the table below is selected financial data for the periods presented.
| Eleven Months August 31, 2003 |
Year Ended August 31, 2003 |
Year Ended August 31, 2004 |
Year Ended August 31, 2004 |
||||||||||||
| (Aggregate— unaudited) |
(Actual) |
(Aggregate— unaudited) |
|||||||||||||
| (in thousands) | |||||||||||||||
| Midstream Segment: |
|||||||||||||||
| Revenues |
$ | 889,527 | $ | 889,527 | $ | 1,852,866 | $ | 1,852,866 | |||||||
| Cost of sales |
823,315 | 823,315 | 1,760,051 | 1,760,051 | |||||||||||
| Operating expenses |
11,193 | 11,193 | 12,541 | 12,541 | |||||||||||
| General and administrative |
7,599 | 7,599 | 10,222 | 10,222 | |||||||||||
| Depreciation and amortization |
9,056 | 9,056 | 12,451 | 12,451 | |||||||||||
| Segment operating income |
$ | 38,364 | $ | 38,364 | $ | 57,601 | $ | 57,601 | |||||||
| Transportation and Storage Segment: |
|||||||||||||||
| Revenues |
$ | 41,500 | $ | 41,500 | $ | 113,938 | $ | 113,938 | |||||||
| Cost of sales |
2,123 | 2,123 | 11,270 | 11,270 | |||||||||||
| Operating expenses |
13,853 | 13,853 | 30,571 | 30,571 | |||||||||||
| General and administrative |
5,021 | 5,021 | 8,372 | 8,372 | |||||||||||
| Depreciation and amortization |
2,814 | 2,814 | 12,255 | 12,255 | |||||||||||
| Segment operating income |
$ | 17,689 | $ | 17,689 | $ | 51,470 | $ | 51,470 | |||||||
| Retail Propane Segment: |
|||||||||||||||
| Retail propane revenues |
$ | — | $ | 463,392 | $ | 315,177 | $ | 536,636 | |||||||
| Other revenues |
— | 59,385 | 36,768 | 64,697 | |||||||||||
| Liquids marketing |
— | 1,333 | 863 | 1,232 | |||||||||||
| Retail propane cost of sales |
— | 236,307 | 174,769 | 296,206 | |||||||||||
| Other cost of sales |
— | 17,213 | 10,463 | 18,816 | |||||||||||
| Operating expenses |
— | 148,623 | 102,326 | 162,086 | |||||||||||
| Depreciation and amortization |
— | 37,442 | 31,104 | 46,299 | |||||||||||
| Segment operating income |
$ | — | $ | 84,525 | $ | 34,146 | $ | 79,158 | |||||||
| Wholesale Propane Segment: |
|||||||||||||||
| Revenues |
$ | — | $ | 10,719 | $ | 5,358 | $ | 9,394 | |||||||
| Cost of sales |
— | 9,620 | 4,742 | 8,345 | |||||||||||
| Operating expenses |
— | 3,508 | 1,936 | 2,911 | |||||||||||
| Depreciation and amortization |
— | 494 | 417 | 601 | |||||||||||
| Segment operating loss |
$ | — | $ | (2,903 | ) | $ | (1,737 | ) | $ | (2,463 | ) | ||||
| Foreign Wholesale Segment: |
|||||||||||||||
| Revenues |
$ | — | $ | 36,647 | $ | 21,987 | $ | 38,547 | |||||||
| Cost of sales |
— | 34,016 | 20,129 | 35,065 | |||||||||||
| Depreciation and amortization |
— | 23 | 15 | 25 | |||||||||||
| Segment operating income |
$ | — | $ | 2,608 | $ | 1,843 | $ | 3,457 | |||||||
| Unallocated selling, general and administrative expenses |
$ | 552 | $ | 14,589 | $ | 12,517 | $ | 22,617 | |||||||
| Consolidated Information: |
|||||||||||||||
| Revenues |
$ | 931,027 | $ | 1,502,503 | $ | 2,346,957 | $ | 2,617,310 | |||||||
| Cost of sales |
825,438 | 1,122,594 | 1,981,424 | 2,129,753 | |||||||||||
| Gross profit |
105,589 | 379,909 | 365,533 | 487,557 | |||||||||||
| Operating expenses |
25,046 | 177,177 | 147,374 | 208,109 | |||||||||||
| Selling, general and administrative |
13,172 | 27,209 | 31,111 | 41,211 | |||||||||||
| Depreciation and amortization |
11,870 | 49,829 | 56,242 | 71,631 | |||||||||||
| Consolidated operating income |
$ | 55,501 | $ | 125,694 | $ | 130,806 | $ | 166,606 | |||||||
| Equity in earnings of affiliates |
1,423 | 2,794 | 363 | 859 | |||||||||||
| Interest expense |
12,453 | 48,193 | 41,217 | 53,971 | |||||||||||
| Gain on Energy Transfer transaction |
— | — | 395,253 | 395,253 | |||||||||||
| Gain (loss) on disposal of assets |
— | 430 | (1,006 | ) | (1,246 | ) | |||||||||
| Other, net |
202 | (3,011 | ) | 516 | 450 | ||||||||||
| Minority interests from continuing operations |
— | (876 | ) | (35,164 | ) | (35,736 | ) | ||||||||
| Income tax expense |
4,432 | 5,455 | 2,792 | 2,812 | |||||||||||
| Income from continuing operations |
40,241 | — | 446,759 | 469,403 | |||||||||||
| Income from discontinued operations, net of minority interests |
5,994 | 5,994 | 3,458 | 3,458 | |||||||||||
| Net income |
$ | 46,235 | $ | 77,377 | $ | 450,217 | $ | 472,861 | |||||||
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Revenues. Total revenues were $2,347.0 million for the fiscal year ended August 31, 2004 compared to $931.0 million for the eleven months ended August 31, 2003. These revenues reflect a full twelve months of ETC OLP’s revenues consolidated with the revenues of HOLP after the Energy Transfer Transactions occurred (from January 20, 2004 through August 31, 2004). The aggregate revenues for the periods presented would have been total revenues of $2,617.3 million for the year ended August 31, 2004 as compared to aggregate total revenues of $1,502.5 million for the year ended August 31, 2003.
Total midstream and transportation revenues were $1,966.8 million for the year ended August 31, 2004 compared to $931.0 million for the eleven months ended August 31, 2003, an increase of $1,035.8 million or 111.3%. Midstream revenues increased $963.4 million or 108.3% from $889.5 million for the eleven months ended August 31, 2003 to $1,852.9 million for the year ended August 31, 2004. The increase is principally attributable to expanding ETP’s producer services activities and increases in sales volumes during the year ended August 31, 2004.
ETP’s average natural gas sales prices were $5.13 per MMBtu for the year ended August 31, 2004 compared to $4.99 per MMBtu for the eleven months ended August 31, 2003. Average NGLs sales prices increased $0.21 or 55% from $0.38 per gallon for the eleven months ended August 31, 2003 compared to $0.59 per gallon for the year ended August 31, 2004. The market price for NGLs tends to correlate with the price of crude oil.
Transportation and storage revenues were $113.9 million for the year ended August 31, 2004 compared to $41.5 million for the eleven months ended August 31, 2003, an increase of 174.5%. The significant increase in transportation revenues is principally due to the following:
| • | Accounting for Oasis Pipeline. As discussed above, ETP accounted for the Oasis Pipeline as an equity method investment prior to December 27, 2002 when it purchased the remaining 50% in Oasis Pipeline. As a result, the eleven months ended August 31, 2003 only includes the results of operations subsequent to December 27, 2002. Had Oasis Pipeline been consolidated for the entire 2003 reporting period, transportation revenues would have been $49.5 million for the eleven months ended August 31, 2003. |
| • | Increased Volumes. During the year ended August 31, 2004, ETP transported 1,091,000 MMBtu/d through its transportation pipelines compared to 921,000 MMBtu/d during the period from December 27, 2002 to August 31, 2003, an increase of 170,000 MMBtu/d or 18.5%. The volume increase is a result of ETP’s decision to pursue additional volumes on the middle and west end of the system on the Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, and the completion of the Bossier Pipeline in June 2004. The ET Fuel System and Bossier Pipeline contributed $18.9 million in revenues from the date of acquisition or completion through August 31, 2004. ETP believes that it will be able to increase throughput on, and therefore revenue from, the ET Fuel System in future years through the addition of interconnects with other pipelines and other industrial end-users, the addition of new customers and more active management of the ET Fuel System and storage facilities to capitalize on market opportunities. In addition, a wide basis differential between the Waha and Katy Hubs provides an incentive to transport increased volumes of natural gas to a more attractive marketplace. |
For the fiscal year ended August 31, 2004, ETP had retail propane revenues of $315.2 million, domestic wholesale propane revenues of $5.4 million, foreign wholesale propane revenues of $22.0 million, other revenues of $36.8 million and net liquids marketing activities of $0.8 million with no propane revenues reflected in the eleven months ended August 31, 2003. These revenues reflect only the amounts earned after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). As a comparison, for the fiscal ended August 31, 2004, Heritage would have reflected aggregate retail propane revenues of $536.6 million as compared to historical revenues of $463.4 million in the fiscal year ended August 31, 2003 for Heritage. Of the $73.2 million increase from Heritage, $37.4 million is due to the increase in volumes sold by customer service locations added
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through acquisitions, $43.7 million is due to higher selling prices, offset by a decrease of $7.9 million due to the decrease in weather-related volumes described above. Aggregate domestic wholesale propane revenues were $9.4 million for the fiscal year ended August 31, 2004 as compared to historical $10.7 million for the fiscal year ended August 31, 2003. Of the decrease, $2.2 million is due to the lost commercial customers described above, offset by a $0.9 million increase related to higher selling prices. Aggregate foreign wholesale propane revenues were $38.5 million as compared to historical results of $36.6 million for the fiscal year ended August 31, 2003, due to a $7.1 million increase related to higher selling prices offset by a decrease of $5.2 million due to the decrease in volumes described above. Aggregate other revenues were $64.7 million compared to $59.4 million for the fiscal year ended August 31, 2003, and net liquids marketing activities would have been $1.2 million as compared to $1.3 million for the fiscal year ended August 31, 2003.
Costs of Sales. Total cost of products sold increased to $1,981.4 million for the fiscal year ended August 31, 2004 as compared to $825.4 million for the eleven months ended August 31, 2003. These costs of sales reflect the full twelve months of ETC OLP’s cost of sales consolidated with the cost of sales of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total cost of sales for the periods presented, would have been $2,129.8 million for the fiscal year ended August 31, 2004 as compared to the aggregate total cost of sales of $1.122.6 million for the year ended August 31, 2003.
Total cost of sales for ETP’s midstream and transportation and storage segments was $1,771.3 million for the year ended August 31, 2004 compared to $825.4 million for the eleven months ended August 31, 2003, an increase of $945.9 million or 114.6%.
Midstream cost of sales was $1,760.0 million for the year ended August 31, 2004 compared to $823.3 million for the eleven months ended August 31, 2003, an increase of $936.7 million or 113.8%. This increase was principally attributable to the increase in sales volumes and prices during the year ended August 31, 2004 as ETP expanded its marketing efforts. Transportation and storage cost of sales was $11.3 million for the year ended August 31, 2004 and $2.1 million for the eleven months ended August 31, 2003. The transportation and storage segment generally retains a portion of each shipper’s gas to compensate for fuel used in operating the pipeline. The actual usage of gas can differ from the amounts retained from our customers. Cost of sales activity is typically generated from the sale of excess inventory or the recognition, either positive or negative, of unaccounted fuel within the pipeline system.
For the fiscal year ended August 31, 2004, ETP had retail propane cost of sales of $174.8 million, domestic wholesale propane cost of sales of $4.7 million, foreign wholesale propane cost of sales of $20.1 million, and other cost of sales of $10.5 million with no propane cost of sales reflected in the fiscal year ended August 31, 2003. These costs reflect only the amounts that were incurred after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). As a comparison, for the fiscal year ended August 31, 2004, aggregated retail propane cost of sales would have been $296.2 million as compared to the historical cost of sales of $236.3 million in the fiscal year ended August 31, 2003. Of the $59.9 million aggregate increase from Heritage, $16.3 million reflects changes in volumes described above and $43.6 reflects the increase due to higher selling prices. Aggregate domestic wholesale propane cost of sales would have been $8.3 million as compared to historical cost of sales of $9.6 million for the fiscal year ended August 31, 2003. Of the decrease, $1.9 million is due to volume decreases described above offset by $0.6 million increase due to increased selling prices. Aggregate foreign wholesale propane cost of sales would have been $35.1 million as compared to historical cost of sale of $34.0 million for the fiscal year ended August 31, 2003. Of the increase, $5.8 million is related to higher selling prices offset by a decrease of $4.7 million due to volume decreases described above. Aggregate other cost of sales would $18.8 million as compared to historical other cost of sales of $17.2 million for the fiscal year ended August 31, 2003.
Operating Expenses. Operating expenses increased $122.4 million to $147.4 million for the fiscal year ended August 31, 2004 as compared to $25.0 million for the eleven months ended August 31, 2003. These operating expenses reflect a full fiscal year of ETC OLP’s operating expenses consolidated with the operating
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expenses of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total operating expenses for the periods presented would have been $208.1 million for the fiscal year ended August 31, 2004 as compared to the aggregate total operating expenses of $177.2 million for the year ended August 31, 2003.
Total midstream and transportation and storage operating expenses were $43.1 million for the year ended August 31, 2004 compared to $25.0 million for the eleven months ended August 31, 2003, an increase of $18.1 million, or 72.4%.
Midstream operating expenses increased from $11.2 million for the eleven months ended August 31, 2003 to $12.5 million for the year ended August 31, 2004. The increase was principally attributable to a $1.4 million effect of reporting on an additional month during the year ended August 31, 2004 compared to the eleven months ended August 31, 2003.
Transportation and storage operating expenses were $30.6 million for the year ended August 31, 2004 compared to $13.9 million for the eleven months ended August 31, 2003, an increase of $16.7 million or 120.1%. The increase was principally attributable to the Oasis Pipeline being accounted for as an equity method investment prior to December 27, 2002, $11.0 million in additional operating expenses related to the acquisition of the ET Fuel System in June 2004, and the completion of the Bossier Pipeline in June 2004.
Total operating expenses for the propane operations were $104.3 million for the fiscal year ended August 31, 2004, which reflects from the date of the Energy Transfer Transaction. ETP’s propane operations would have reflected total aggregate operating expense of $165.0 million for the full year as compared to aggregate total operating expenses of $152.1 million for the year ended August 31, 2003, or an increase of $12.9 million. Of this aggregate increase, approximately $12.4 million was attributable to employee-related expenses due to an increase in ETP’s employee base from acquisitions. During fiscal 2004, HOLP purchased the other 50% of Bi-State Partnership, which was accounted for as an equity method investment prior to the purchase in December 2003.
Selling, General and Administrative Expenses. Selling, general and administrative expenses were $31.1 million for the fiscal year ended August 31, 2004 compared to $13.1 million for the eleven months ended August 31, 2003. Of this increase, $4.5 million is due to the Energy Transfer Transactions described above. These selling, general and administrative expenses reflect the full fiscal year of ETC OLP’s selling, general and administrative expenses consolidated with the selling, general and administrative expenses of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total selling, general, and administrative expenses for the periods presented, would have been $41.2 million for the fiscal year ended August 31, 2004 as compared to the aggregate total of $27.2 million for the year ended August 31, 2003.
Total general and administrative operating expenses for ETP’s midstream and transportation segments were $18.6 million for the year ended August 31, 2004 compared to $12.6 million for the eleven months ended August 31, 2003, an increase of $6.0 million.
Midstream general and administrative expenses increased $2.6 million from $7.6 million for the eleven months ended August 31, 2003 to $10.2 million principally due to a $1.2 million effect of reporting on an additional month for the year ended August 31, 2004, a $2.5 million increase in compensation expense related to ETP’s producer services, and a $0.4 million increase in merger and reporting compliance expenses. The increase was offset by a $1.5 million increase in costs allocated to the transportation and storage segment for certain management services provided by the midstream segment.
Transportation and storage general and administrative expenses also increased $3.4 million during the eleven months ended August 31, 2003 from $5.0 million to $8.4 million for the year ended August 31, 2004. The increase is principally attributable to the 2003 reporting period not including general and administrative expenses for the Oasis Pipeline prior to December 27, 2002 because it was accounted for as an equity method investment. Selling, general and administrative expenses are not allocated to ETP’s propane segments.
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The total unallocated selling, general, and administrative expenses were $12.5 million for the fiscal year ended August 31, 2004, which includes $4.1 million of ETP unallocated selling, general and administrative expenses. On an aggregate basis, these unallocated selling general and administrative expenses would have been $22.6 million for the full twelve months ended August 31, 2004 as compared to the aggregate amount of $14.6 million for the fiscal year ended August 31, 2003.
Depreciation and Amortization. Depreciation and amortization expense for the fiscal year ended August 31, 2004 was $56.2 million compared to $11.9 million for the eleven months ended August 31, 2003, an increase of $44.3 million. This depreciation and amortization reflects the full fiscal year of ETC OLP’s depreciation and amortization consolidated with the depreciation and amortization of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Of the increase, $39.1 million is due to the Energy Transfer Transactions for the depreciation on ETP’s propane assets and the step up in fair value for ETC OLP’s assets from January 20, 2004 through August 31, 2004.
Midstream depreciation and amortization increased $3.4 million or 37.8% from $9.0 million for the eleven months ended August 31, 2003 to $12.4 million for the year ended August 31, 2004 due to an additional month in the 2004 reporting period.
Transportation and storage depreciation and amortization increased $9.4 million or 335.7% from $2.8 million for the eleven months ended August 31, 2003 to $12.2 million for the year ended August 31, 2004. The increase was attributable to increased depreciation as a result of the consolidation of the Oasis Pipeline in December 2002 and the acquisition of the ET Fuel System in June 2004.
Operating Income. For the fiscal year ended August 31, 2004, we had operating income of $130.8 million as compared to operating income of $55.5 million for the eleven months ended August 31, 2003. This increase is primarily due to the Energy Transfer Transactions and changes in revenues and expenses described above. This operating income reflects the full fiscal year of ETC OLP’s operating income consolidated with the operating income of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total operating income for the periods presented, would have been $166.6 million for the fiscal year ended August 31, 2004 as compared to $125.7 million for the year ended August 31, 2003.
Equity Income in Affiliates. Equity income in affiliates was $1.4 million for the eleven months ended August 31, 2003 compared to $0.4 million for the fiscal year ended August 31, 2004. The decrease was principally due to the consolidation of the Oasis Pipeline in December 2002.
Interest Expense. Interest expense was $41.2 million for the fiscal year ended August 31, 2004 as compared to $12.4 million for the eleven months ended August 31, 2003. This interest expense reflects the full fiscal year of ETC OLP’s interest expense consolidated with the interest expense of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Of this increase, $20.7 million is related to the interest expense of HOLP after the Energy Transfer Transactions and $5.9 million is the result of additional interest in ETP’s midstream and transportation and storage segments due to the Energy Transfer Transactions and the acquisition of ET Fuel System in June 2004. In addition, ETP incurred $8.2 million in deferred financing costs during the year ended August 31, 2004, which ETP is amortizing on a straight-line basis over the remaining term of the related credit facility and accounting for it in interest expense.
Gain on Energy Transfer Transactions. In accordance with EITF 90-13 and SFAS 141, we recorded a gain of $395,253 million during the year ended August 31, 2004 with as a result of the Energy Transfer Transactions. The total gain recorded was increased to the extent that distributions received by us from ETC OLP in the transactions exceeded our investment in ETC OLP prior to the transactions.
Income Tax Expense. Income tax expense was $2.8 million for the fiscal year ended August 31, 2004 compared to $4.4 million for the eleven months ended August 31, 2003. As a partnership, ETP is not subject to income taxes. However, Oasis Pipeline, Heritage Service Company, and Heritage Holdings, wholly owned
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subsidiaries, are corporations that are subject to income taxes. The decrease in income taxes is due to lower taxable income in Oasis Pipeline offset by the increase from the income taxes in Heritage Holdings after the Energy Transfer Transactions.
Income from continuing operations. Income from continuing operations for the year ended August 31, 2004 was $446.7 million, as compared to income from continuing operations of $40.2 million for the year ended August 31, 2003. The increase from fiscal 2003 compared to fiscal year 2004 is principally due to the gain on the Energy Transfer Transactions recorded in the year period ended August 31, 2004 that was not present for the year ended August 31, 2003.
Minority interest expense from continuing operations. Minority interest expense from continuing operations was $35.2 million for the year ended August 31, 2004 with no minority interest recorded for the year ended August 31, 2003. The minority interest expense primarily represents partnership interests in ETP that are not owned by us. There were no minority interests prior to the Energy Transfer Transactions. The minority interest from continuing operations for the year ended August 31, 2004 was not affected by the gain on the Energy Transfer Transactions because this gain was entirely attributable to ETE prior to the Energy Transfer Transactions.
Discontinued operations. Income from discontinued operations was $6.2 million for the year ended August 31, 2004 compared to $6.0 for the eleven months ended August 31, 2003. Minority interest expense from discontinued operations was $2.7 million for the year ended August 31, 2004 with no minority interest in discontinued operations for the eleven months ended August 31, 2003 because there were no minority interests prior to the Energy Transfer Transactions.
Net Income. Net income for the year ended August 31, 2004 was $450.2 million compared to $46.2 million for the eleven months ended August 31, 2003. The affects of the Energy Transfer Transactions described above together with the increase in acquisition related income, attributed to this increase.
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EBITDA, As Adjusted. EBITDA, as adjusted, increased $75.1 million to $152.5 million for the fiscal year ended August 31, 2004 as compared to EBITDA, as adjusted, of $77.4 million for the eleven months ended August 31, 2003. This increase is due to the Energy Transfer Transactions and the operating performance described above. This EBITDA, as adjusted, reflects the full twelve months of ETE’s EBITDA, as adjusted, consolidated with the EBITDA, as adjusted, of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total EBITDA, as adjusted, for the periods presented, would have been $205.3 million for the fiscal year ended August 31, 2004 as compared to the aggregate EBITDA, as adjusted, of $188.3 million for the eleven months ended August 31, 2003. EBITDA, as adjusted, is computed as follows:
| Fiscal Year Ended |
||||||||||||||||||||
| August 31, 2003 |
August 31, 2003 |
August 31, 2003 |
August 31, 2004 |
August 31, 2004 |
||||||||||||||||
| (Aggregate) | (Heritage Historical) |
(Actual) | (Aggregate) | |||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Net income reconciliation | ||||||||||||||||||||
| Net income |
$ | 46,235 | $ | 77,377 | $ | 31,142 | $ | 450,217 | $ | 472,861 | ||||||||||
| Gain on Energy Transfer Transactions |
— | — | — | (395,253 | ) | (395,253 | ) | |||||||||||||
| Depreciation and amortization |
11,870 | 49,829 | 37,959 | 56,242 | 71,631 | |||||||||||||||
| Interest |
12,453 | 48,193 | 35,740 | 41,217 | 53,971 | |||||||||||||||
| Taxes |
4,432 | 5,455 | 1,023 | 2,792 | 2,812 | |||||||||||||||
| Non-cash compensation expense |
— | 1,159 | 1,159 | 42 | 1,274 | |||||||||||||||
| Other expense (income) |
(202 | ) | 3,011 | 3,213 | (516 | ) | (450 | ) | ||||||||||||
| Depreciation, amortization, and interest of investee |
1,003 | 1,904 | 901 | 440 | 762 | |||||||||||||||
| Depreciation and amortization from discontinued operations |
1,591 | 1,591 | — | 2,249 | 2,249 | |||||||||||||||
| Minority interests in operating partnership |
— | 256 | 256 | — | 178 | |||||||||||||||
| (Gain) loss on disposal of assets |
— | (430 | ) | (430 | ) | 1,006 | 1,246 | |||||||||||||
| EBITDA, as adjusted (a) |
$ | 77,382 | $ | 188,345 | $ | 110,963 | $ | 158,436 | $ | 211,281 | ||||||||||
| (a) | EBITDA, as adjusted, is defined as our earnings before interest, taxes, depreciation (adjusted for depreciation directly attributable to minority interests), amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, gain or loss on discontinued operations (net of minority interests), gain on the Energy Transfer Transactions and other expenses. ETP presents EBITDA, as adjusted, on a partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the common units of ETP awarded under ETP’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the gain or loss arising from ETP’s disposal of assets, discontinued operations, and the gain on the Energy Transfer Transactions are not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (1) is not a measure of performance calculated in accordance with generally accepted accounting principles and (2) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in its consolidated financial statements. |
| EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management of ETP believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of ETP’s ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to our investors for trending, analyzing and benchmarking the operating results of ETP from period to period as compared to other companies that may have different financing and capital structures. |
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| The presentation of EBITDA, as adjusted, allows investors to view ETP’s performance in a manner similar to the methods used by management and provides additional insight to ETP’s operating results. |
| EBITDA, as adjusted, is used by management to determine its operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of ETP’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. ETP has a large number of business locations in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full partnership basis, ETP adds back the minority interest of its general partner because net income per limited partner unit is reported net of the general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash expense item resulting from its unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the its business. The inclusion of these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare ETP’s operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ETP’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in ETP’s operating results but are not classified in interest, depreciation and amortization. We do not include gain or loss on the sale of assets when determining EBITDA, as adjusted, since including non-cash income or loss resulting from the sale of assets increases/decreases the performance measure in a manner that is not related to the true operating results of our business. In addition, ETP’s debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “Debt Obligations” in this prospectus. |
| There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, ETP’s calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by ETP and Heritage in the past. Management compensates for these limitations by considering EBITDA, as adjusted in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities. |
Eleven Months Ended August 31, 2003 Compared to Nine Months Ended September 30, 2002 for Aquila Gas Pipeline Corporation
Revenues. Total revenues were $931.0 million for the eleven months ended August 31, 2003 compared to $933.1 million for the nine months ended September 30, 2002, a decrease of $2.1 million, or 0.002%. Midstream revenues were $889.5 million for the eleven months ended August 31, 2003 compared to $933.1 million for the nine months ended September 30, 2002, an decrease of $43.6 million or 4.7%. The decrease is primarily due to the difference in the number of operating periods. In order to fully understand the results of operations, we have also considered the impact of volumes and prices on ETP’s business as noted below.
Volumes. Natural gas sales volumes were 490,000 MMBtu/d for the eleven months ended August 31, 2003 compared to 1,147,000 MMBtu/d for the nine months ended September 30, 2002, a decrease of 657,000 MMBtu/d, or 57.3%. NGL sales volumes were 9,000 Bbls/d for the eleven months ended August 31, 2003 compared to 19,000 Bbls/d for the nine months ended September 30, 2002, a decrease of 10,000 Bbls/d or 52.6%. Natural gas sales volumes decreased significantly as a result of the smaller scope of our marketing activities as compared to Aquila Gas Pipeline’s (the Predecessor’s) extensive marketing and trading activities. NGL sales volumes decreased due to ETP frequent election to bypass its La Grange processing plant and deliver unprocessed natural gas from ETP’s Southeast Texas System directly into the Oasis Pipeline during the portion of the eleven month
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period ended August 31, 2003 when it owned 100% of Oasis Pipeline. ETP elected to bypass the La Grange processing plant to avoid unfavorable processing margins.
Average realized natural gas sales prices were $4.99 per MMBtu for the eleven months ended August 31, 2003 compared to $2.72 per MMBtu for the nine months ended September 30, 2002, an increase of $2.27 per MMBtu or 83.5%. In addition, average realized NGL sales prices were $0.38 per gallon for the eleven months ended August 31, 2003 compared to $0.32 per gallon for the nine months ended September 30, 2002, an increase of $0.06 per gallon or 18.8%.
Transportation revenues were $41.5 million for the eleven months ended August 31, 2003. ETP’s results for the nine months ended September 30, 2002 and for the three-month period ended December 27, 2002 exclude revenues of Oasis Pipeline because its investment in Oasis Pipeline was treated as an equity method investment prior to December 27, 2002.
Cost of Sales. Total cost of sales was $825.4 million for the eleven months ended August 31, 2003 compared to $880.1 million for the nine months ended September 30, 2002, a decrease of $54.7 million or 6.2%. Midstream cost of sales was $823.3 million for the eleven months ended August 31, 2003 compared to $880.1 million for the nine months ended September 30, 2002, a decrease of $56.8 million, or 6.5%. The decrease is primarily due to the difference in the number of operating periods. The transportation segment sold excess inventory during the eleven months ended August 31, 2003 resulting in a cost of sales of $2.1 million. The transportation segment only periodically engages in activities that generate cost of sales.
Operating Expenses. Operating expenses were $25.0 million for the eleven months ended August 31, 2003 compared to $12.7 million for the nine months ended September 30, 2002, an increase of $12.3 million, or 96.9%. This increase was due to the inclusion of approximately $4.9 million of operating expenses associated with Oasis Pipeline subsequent to December 27, 2002 and an additional two months of operations accounted for during the 2003 reporting period compared to the 2002 reporting period. Oasis Pipeline’s operating expenses were not included in Aquila Gas Pipeline’s results for the nine-month period ended September 30, 2002, because Aquila Gas Pipeline accounted for its investment in Oasis Pipeline under the equity method.
General and Administrative Expenses. General and administrative expenses were $13.1 million for the 11 months ended August 31, 2003 compared to $9.6 million for the nine months ended September 30, 2002, an increase of $3.5 million or 36.5%. On an annualized basis this represents a 11.7% increase. This annualized increase resulted primarily from higher employee bonuses and increased travel and insurance costs as well as the inclusion of general and administrative expense of Oasis Pipeline subsequent to December 27, 2002.
Depreciation and Amortization. Depreciation and amortization expense was $11.9 million for the eleven months ended August 31, 2003 compared to $22.9 million for the nine months ended September 30, 2002, a decrease of $11.0 million, or 48.0%. Depreciation and amortization expense decreased for the eleven months ended August 31, 2003 primarily due to the acquisition of midstream assets from Aquila Gas Pipeline, which resulted in a reduction in the basis on which these assets are depreciated. In addition, Aquila Gas Pipeline amortized $2.4 million during the nine months ended September 30, 2002 related to a transportation rights contract that has expired. This decrease was partially offset by the inclusion of $2.8 million of depreciation and amortization expense of Oasis Pipeline subsequent to December 27, 2002.
Equity in Net Income of Affiliates. Equity in net income of affiliates was $1.4 million for the eleven months ended August 31, 2003 compared to $5.4 million for the nine months ended September 30, 2002, a decrease of $4.0 million, or 74.1%. This decrease resulted from equity in net income of affiliates for the eleven months ended August 31, 2003 not reflecting any equity earnings associated with Oasis Pipeline subsequent to December 27, 2002 while Oasis Pipeline’s earnings were recognized under the equity method of accounting for the three months ended December 27, 2002 and the nine months ended September 30, 2002. Equity earnings from Oasis Pipeline included in total equity in net income (loss) of affiliates was $1.6 million and $5.4 million for the three months ended December 27, 2002 and the nine months ended September 30, 2002, respectively.
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Interest Expense, Net. Interest expense was $12.5 million for the eleven months ended August 31, 2003 compared to $3.9 million for the nine months ended September 30, 2002, an increase of $8.6 million or 220.5%. The increase was primarily due to the increased borrowings used to finance the purchase of midstream assets from Aquila Gas Pipeline and Dow Hydrocarbons Resources, Inc.
Income Tax Expense. Income tax expense was $4.4 million for the eleven months ended August 31, 2003 compared to a benefit of $0.5 million for the nine months ended September 30, 2002. As a partnership, neither we nor ETP is subject to income taxes. However, Oasis Pipeline is a corporation that is subject to income taxes at an effective rate of 35%. The benefit for the nine months ended September 30, 2002 was related to the operating results of Aquila Gas Pipeline, which is a corporation subject to income taxes.
Income From Continuing Operations. Income from continuing operations for the eleven months ended August 31, 2003 was $40.2 million compared to $4.7 million for the nine months ended August 31, 2002. The increase is principally due to the reasons described above.
Income From Discontinued Operations. On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191.6 million, including certain adjustments as defined in the purchase and sale agreement. Revenues from the Elk City System were $92.4 million for the year ended August 31, 2003. Costs and expenses were $79.1 million for the year ended August 31, 2003. Income from discontinued operations for the year ended August 31, 2003 was $6.0 million.
Net Income. Net income for the eleven months ended August 31, 2003 was $46.2 million compared to $4.7 million for the nine months ended September 30, 2002, an increase of $41.5 million, or 883%. The increase in net income was primarily due to the reasons described above.
Heritage—Results of Operations
Heritage amounts discussed below reflect 100% of the results of M-P Energy Partnership. M-P Energy Partnership is a Canadian general partnership in which Heritage owned a 60% interest. Because M-P Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to Heritage’s net income is not significant and the minority interest of this partnership not owned by Heritage is excluded from the EBITDA, as adjusted, calculation. All other financial information and operating data included in management’s discussion and analysis of financial condition and results of operations includes references to the foreign wholesale results of M-P Energy Partnership.
Fiscal Year Ended August 31, 2003 Compared to the Fiscal Year Ended August 31, 2002
Volume. Total retail gallons sold in fiscal year 2003 were 375.9 million, an increase of 46.3 million from the 329.6 million gallons sold in fiscal year 2002. Of the increase in volume, approximately 6.0 million gallons were attributable to the volume added through acquisitions and approximately 40.3 million gallons were attributable to colder weather conditions in 2003 in some of Heritage’s areas of operations, offset by warmer than normal weather conditions in other areas of operations.
Heritage sold approximately 74.3 million wholesale gallons during fiscal year 2003, of which 15.3 million were domestic wholesale and 59.0 million were foreign wholesale. In fiscal year 2002, Heritage sold 16.8 million domestic wholesale gallons and 65.3 million foreign wholesale gallons. The 6.3 million gallon decrease in foreign wholesale volumes of M-P Energy Partnership was primarily due to an exchange contract that was in effect during fiscal year 2002, which was not economical to renew during fiscal year 2003.
Revenues. Total revenues for fiscal year 2003 were $571.4 million, an increase of $109.1 million, as compared to $462.3 million in fiscal year 2002. Retail revenues for fiscal year 2003 were $463.4 million as compared to $365.3 million for fiscal year 2002, an increase of $98.1 million, of which $40.9 million was primarily due to higher selling prices, and $49.8 million was primarily due to the increase in gallons sold as a
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result of colder weather conditions, and $7.4 million was due to the increase in gallons sold by customer service locations added through acquisitions. Selling prices in all the reportable segments increased from last year in response to higher supply costs. Domestic wholesale revenues increased $0.7 million to $10.7 million, due to an increase of approximately $1.7 million related to higher selling prices, offset by a decrease of approximately $1.0 million related to a decrease in gallons sold. Foreign wholesale revenues were $36.6 million for fiscal year 2003 as compared to $31.2 million for fiscal year 2002, an increase of $5.4 million primarily due to an approximate $9.3 million increase related to higher selling prices offset by an approximate $3.9 million decrease related to lower volumes as described above. Net liquids marketing revenues increased from $0.5 million in fiscal year 2002 to $1.3 million in fiscal year 2003, primarily due to more favorable movement in product prices in the current fiscal year. Other domestic revenues increased by $4.1 million to $59.4 million for fiscal year 2003, compared to $55.3 million for fiscal year ended 2002 primarily as a result of acquisitions.
Cost of Products Sold. Total cost of sales increased $58.9 million to $297.1 million as compared to $238.2 million for fiscal year 2002. Retail fuel cost of sales increased $51.7 million to $236.3 million for fiscal year 2003, of which approximately $29.1 million was due to increased volumes, and approximately $22.6 million was due to higher supply costs. U.S. wholesale cost of sales decreased $0.1 million to $9.6 million. Foreign wholesale cost of sales increased $4.7 million to $34.0 million, of which approximately $8.4 million was due to increased product costs this fiscal year, offset by an approximate decrease of $3.7 million attributable to the decreased volumes described above. Other cost of sales increased $2.6 million to $17.2 million for fiscal year 2003 primarily due to acquisitions.
Gross Profit. Total gross profit increased to $274.3 million in fiscal year 2003 as compared to $224.1 million in fiscal year 2002, due to the increases in volumes and revenues described above, and the results of acquisitions, offset in part by increases in product costs. For fiscal year 2003, retail fuel gross profit was $227.1 million, domestic wholesale fuel gross profit was $1.1 million, liquids marketing gross profit was $1.3 million, other gross profit was $42.2 million, and foreign wholesale gross profit was $2.6 million. As a comparison, for fiscal year 2002, Heritage recorded retail fuel gross profit of $180.7 million, domestic wholesale fuel gross profit of $0.3 million, liquids marketing gross profit of $0.5 million, other gross profit of $40.6 million and foreign wholesale gross profit of $2.0 million.
Operating Expenses. Operating expenses were $152.1 million for fiscal year 2003 as compared to $133.2 million for fiscal year 2002. The increase of $18.9 million is primarily the result of $6.8 million of additional operating expenses incurred for employee wages and benefits related to the growth of Heritage from acquisitions made during fiscal year 2002, an increase of $5.5 million in the performance-based compensation plan expense due to higher operating performance, an increase of approximately $5.5 million in operating expenses in certain areas of ETP’s operations due to acquisitions and to accommodate increased winter demand, and industry-wide increases in business insurance costs of $1.1 million.
Selling, General and Administrative. Selling, general and administrative expenses were $14.0 million for fiscal year 2003 as compared to $13.0 million for fiscal year 2002. This increase is primarily related to the performance-based compensation plan expense in 2003 that was not incurred in 2002, offset by a $0.7 million decrease in deferred compensation expense related to the adoption of FASB Statement No. 123 Accounting for Stock-Based Compensation (SFAS 123).
Depreciation and Amortization. Depreciation and amortization for fiscal year 2003 was $37.9 million, an increase of $0.9 million as compared to $37.0 million in fiscal year 2002. The increase is attributable to current year acquisitions.
Operating Income. Heritage reported operating income of $70.2 million in fiscal year 2003 as compared to operating income of $41.0 million for fiscal year 2002. This increase is a combination of increased gross profit and a $0.7 million increase due to the adoption of SFAS 123, offset by increased operating expenses described above.
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Interest Expense. Interest expense for fiscal year 2003 was $35.7 million, a decrease of $1.6 million as compared to $37.3 million in fiscal year 2002. The decrease was primarily attributable to the retirement of a portion of outstanding debt during the year.
Other Expense. Other expense for fiscal year 2003 was $3.2 million, an increase of $2.9 million as compared to $0.3 million in fiscal year 2002. The increase was primarily attributable to the reclassification into earnings of a $2.8 million loss on marketable securities in fiscal year 2003 that was previously recorded as accumulated other comprehensive loss on the balance sheet.
Taxes. Taxes for the year ended August 31, 2003 were $1.0 million due to the tax expense incurred by Heritage’s corporate subsidiaries and other franchise taxes owed. Of the $1.0 million increase, $0.3 million was incurred in connection with the liquidation of Guilford Gas Service, Inc. during the fiscal year ended August 31, 2003. There was no tax expense for these subsidiaries for the year ended August 31, 2002.
Net Income. Heritage reported net income of $31.1 million, or $1.79 per ETP limited partner unit, for fiscal year 2003, an increase of $26.2 million from net income of $4.9 million for fiscal year 2002. The increase is primarily the result of the increase in operating income, which includes a $0.7 million decrease in expenses due to the adoption of SFAS 123, partially offset by the increase in other expenses and taxes described above.
EBITDA, As Adjusted. EBITDA, as adjusted, increased $29.5 million to $111.0 million for fiscal year 2003, as compared to EBITDA, as adjusted, of $81.5 million for fiscal year 2002. This increase is due to the operating conditions described above and is a record level of EBITDA, as adjusted, for the fiscal year results of Heritage. Please read footnote (e) under “Selected Historical Financial and Operating Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a more detailed discussion of EBITDA, as adjusted.
Liquidity and Capital Resources
Historically, we have relied on cash distributions from ETP to fund any cash requirements for our operations. We are in compliance with all material financial covenants under our term loan agreement.
ETP’s ability to satisfy its obligations will depend upon its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control. In addition, ETP’s cash needs for working capital and capital expenditures will increase substantially as a result of the Houston Pipeline System acquisition.
Future capital requirements of ETP’s business will generally consist of:
| • | maintenance capital expenditures, which includes capital expenditures made to connect additional wells to its natural gas systems in order to maintain or increase throughput on existing assets, and capital expenditures to extend the useful lives of its propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet; |
| • | growth capital expenditures, mainly for customer propane tanks and for constructing new pipelines, processing plants and treating plants; and |
| • | acquisition capital expenditures for the acquisition of new pipeline systems and propane operations. |
We believe that cash generated from the operations of ETP’s businesses will be sufficient to meet its anticipated working capital needs and maintenance capital expenditures. ETP will initially finance all capital requirements by cash flows from operating activities. To the extent that ETP’s working capital needs or future capital requirements exceed cash flows from operating activities:
| • | maintenance capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable; |
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| • | growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities or from other sources; and |
| • | acquisition capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities, other lines of credit, long-term debt, the issuance of additional common units of ETP, or a combination thereof. |
The assets utilized in ETP’s propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its propane business. In addition, ETP does not experience any significant increases attributable to inflation in the cost of these assets or in its propane operations. The assets used in ETP’s midstream and transportation segments, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than new well connects.
In connection with the Houston Pipeline System acquisition, ETP now engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although ETP intends to fund natural gas purchases with cash generated from operations, from time to time it may need to finance the purchase of natural gas to be held in storage with borrowings from its current credit facilities. ETP intends to repay these borrowings with cash generated from operations when the gas is sold.
Nine Months Ended May 31, 2005
ETE’s internally generated cash flows may change in the future due to a number of factors, some of which it cannot control. These include regulatory changes, the price for ETE’s products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of ETP’s acquisitions, including the recently acquired the Houston Pipeline System, and other factors.
Operating Activities. Cash provided by operating activities during the nine months ended May 31, 2005, was $216.8 million as compared to $135.2 million for the nine months ended May 31, 2004. The net cash provided by operations for the nine months ended May 31, 2005 consisted of net income of $121.9 million, and net non-cash items of $51.4 million. Net non-cash items include the gain on the sale of discontinued operations of $144.0 million, offset by non-cash charges of $92.6 million, principally depreciation and amortization. Net working capital increased $43.6 million. Various components of working capital changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, deposits paid and received, purchases of inventories and most notably from the increase in working capital due to the Houston Pipeline System acquisition.
Investing Activities. Cash used in investing activities during the nine months ended May 31, 2005 of $1,038.7 million is comprised of cash paid for acquisitions of $1,117.9 million and $118.6 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of discontinued operations of $191.6 million and proceeds from the sale of idle property of $3.6 million. The cash paid for acquisitions included $13.9 million expended for retail propane acquisitions, and $1,104.0 million expended for the Texas Chalk and Madison Systems and the newly acquired Houston Pipeline System. In addition to cash paid for acquisitions, ETP issued common units valued at $2.5 million, incurred debt of $1.7 million for non-compete agreements and assumed liabilities in connection with the retail propane acquisitions and assumed $415.3 million of liabilities in connection with the Texas Chalk and Madison Systems and Houston Pipeline System acquisitions. ETE also received $2.6 million from the sale of 5% of its investment in ETP GP and ETP LLC to a group of ETP management investors.
Financing Activities. Net cash provided by financing activities during the nine months ended May 31, 2005 was $760.6 million as compared to net cash provided by financing activities of $86.4 million for the nine
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months ended May 31, 2004. In January 2005, ETP successfully completed the issuance of $750.0 million in Rule 144A private placement senior notes. Net proceeds of approximately $741.0 million were used to repay borrowings and accrued interest outstanding under ETP’s then existing $725.0 million term loan facility with a maturity date of January 19, 2008 (the “ETC OLP Term Loan Facility”) and ETC OLP Revolving Credit Facility. ETP also entered into a $700.0 million Revolving Credit Facility in January 2005. Effective June 2, 2005, ETP increased the amount available under the ETP Revolving Credit Facility from $700.0 million to $800.0 million. The ETP Revolving Credit Facility had a net increase of $443.0 million for the nine months ended May 31, 2005, of which the majority was used to finance a portion of the Houston Pipeline System acquisition. The swingline loan option of the ETP Revolving Credit Facility provided $30.0 million of net proceeds that were used for general partnership purposes.
ETC OLP had a net decrease of $725.0 million in its term loan facility for the nine months ended May 31, 2005. ETC OLP borrowed $80.0 million under the ETC OLP Revolving Credit Facility of which $60.0 million was used to fund the acquisition of the Texas Chalk and Madison Systems. The remaining $20.0 million was used for general partnership purposes. The $80.0 million was repaid during the second quarter of fiscal year 2005. Net cash provided by financing activities also included $174.6 million of proceeds from a short-term loan with ETC, an affiliated entity, whereby ETC OLP borrowed the funds to acquire the working natural gas inventory stored in the Bammel storage facilities in connection with the Houston Pipeline System acquisition. The loan was paid in full during the third quarter of fiscal year 2005. ETC OLP incurred $3.1 million in debt issuance costs associated with the loan agreement, which were written off at the time of the repayment of the loan.
Cash provided by financing activities also includes the net decrease in HOLP’s working capital facility of $18.1 million, a net increase in HOLP’s acquisition facility of $18.0 million and a net decrease in HOLP’s long-term debt of $10.0 million. HOLP’s working capital facility decreased because ETP entered its required thirty day clean down period during May 2005, which required ETP to pay the HOLP working capital facility principal down to at least $10.0 million for a period of not less than thirty consecutive days. HOLP completed the 30-day clean down period on June 14, 2005. The increase in the acquisition facility is partially due to funding of acquisitions of propane businesses and other growth capital.
On January 26, 2005, ETP placed $350.0 million of its common units in a private placement to institutional investors as part of the financing of the acquisition of the Houston Pipeline System. In this private placement ETP issued 6,296,294 of its unregistered common units for total consideration of $170.0 million, and it became obligated under a Units Purchase Agreement dated January 14, 2005 to issue an additional 6,666,666 common units for total consideration of $180.0 million. These common units were issued pursuant to an effective shelf registration statement on March 18, 2005. The proceeds from these private placements were used to finance a portion of the Houston Pipeline System acquisition. ETP paid $0.3 million in equity issue costs associated with its $350.0 million common units. ETP’s general partner contributed $7.2 million to maintain its 2% interest in ETP in connection with the $2.5 million of ETP common units issued in connection with certain acquisitions and the $350.0 million of ETP common units issued in the private placement.
Cash received from financing activities is reduced by the distributions ETP paid to its common unitholders and its general partner’s 2% interest of $143.7 million, and other financing costs of $15.9 million related to the issuance of the $750.0 million private placement notes and other debt.
Fiscal Year Ended August 31, 2004
Operating Activities. Cash provided by operating activities during the year ended August 31, 2004 was $122.1 million as compared to cash provided by operating activities of $70.7 million for the eleven months ended August 31, 2003. The net cash provided by operations for the year ended August 31, 2004 consisted of net income of $450.2 million, a net decrease from non-cash charges of $338.5 million ( principally from the gain on the Energy Transfer Transactions and distributions from ETP to minority unitholders) and an increase in working capital of $10.4 million. Various components of working capital changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, purchase of inventories related to the propane operations and the Energy Transfer Transactions.
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Investing Activities. Cash used in investing activities during the year ended August 31, 2004 of $731.8 million is comprised of cash paid for acquisitions of $622.9 million and $109.7 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of idle property of $1.1 million. The cash paid for acquisitions included $166.6 million of cash paid in the Energy Transfer Transactions, including $100 million for the purchase of Heritage Holdings, $16.7 million expended for retail propane acquisitions and $498.5 million expended for the ET Fuel System. Heritage expended $22.5 million of cash for acquisitions of retail propane operations for the period ended January 19, 2004, issued $17.9 million of common units, incurred $2.4 million of payment obligations in connection with non-compete agreements and assumed $3.8 of liabilities in connection with these acquisitions.
Financing Activities. Cash received from financing activities during the year ended August 31, 2004 was $637.5 million. ETC OLP borrowed $325.0 million under its $725.0 million term loan facility that matures on January 19, 2008 (the “ETC OLP Term Loan Facility”) and the proceeds were used to (1) retire $218.5 million of debt outstanding at the time of the Energy Transfer Transactions, (2) satisfy ETC OLP’s accounts payable and other specified liabilities as they became due and (3) fund certain other expenses in connection with the Energy Transfer Transactions. In conjunction with the amendment to the ETC OLP Term Loan Facility on June 2, 2004, ETC OLP borrowed an additional $400.0 million to partially finance the purchase of the ET Fuel System. The cash received from financing activities is net of $8.2 million in debt issuance costs. The net decrease in HOLP’s Bank Facility that matures on January 19, 2008 (the “HOLP Term Loan Facility”) was $79.9 million since the Energy Transfer Transactions, and $35.1 million was used for principal payments on HOLP’s notes and other long-term debt. ETP raised $528.1 million of net proceeds through the sale of 9,200,000 common units at an offering price of $38.69 per unit in January 2004 and offering of 4,500,000 common units at an offering price of $39.20 per unit on June 30, 2004, including an over-allotment option at the offering price of $39.20 per unit for 675,000 exercised on July 2, 2004. Proceeds of $334.3 million from the January 2004 offering were used to finance the Energy Transfer Transactions and for other partnership purposes, including a total distribution of $205.7 million to La Grange Energy in connection with the terms of the Energy Transfer Transactions. The net proceeds of $193.8 million from a public offering of units by ETP and the exercise of the over-allotment were used to repay a portion of the outstanding indebtedness incurred to fund the acquisition of the ET Fuel System and for other partnership purposes. Cash received from financing activities included contributions by the general partner of ETP of $22.2 million to maintain its 2% general partner interest and is reduced by the distributions ETP paid to its common and Class D unitholders and the general partner’s 2% interest of $63.4 million.
ETP Cash Distributions
ETP uses the cash provided by the operating and financing activities of ETC OLP and HOLP to provide distributions to its unitholders. Under its partnership agreement, ETP must distribute to its partners within 45 days after the end of each fiscal quarter, an amount equal to all of its available cash for such quarter. Available cash generally means, with respect to any quarter of ETP, all cash on hand at the end of such quarter less the amount of cash reserves established by its general partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. ETP’s commitment to its unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for ETP’s operations. Heritage (the predecessor to ETP) paid quarterly distributions since its inception in 1996 up to and including the quarterly distribution of $0.325 per common unit paid on January 14, 2004. Heritage had raised its quarterly distribution over the years from $0.25 per ETP unit in 1996 to $0.325 per unit as of the quarterly distribution paid on January 14, 2004. Subsequent to the business combination of ETP and Heritage, ETP has increased the cash distributions per common unit to $0.50 for the quarter ended August 31, 2005 ($2.00 per common unit on an annualized basis). This level of distribution will result in a quarterly distribution of approximately $18.2 million to us attributable to our approximately 36.4 million common units of ETP, $1.5 million attributable to our indirect ownership of the 2% general partner interest and $6.7 million attributable to our indirect ownership of 50% of the incentive distribution rights.
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Energy Transfer Equity
Senior Secured Term Loan Agreement. On June 16, 2005, we entered into a $600 million senior secured term loan agreement that matures on June 16, 2008. Loans in an amount of $600 million were borrowed and amounts repaid under the term loan agreement may not be reborrowed. Loans under the term loan agreement bear interest at our option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of our leverage ratio. Interest on loans under the term loan agreement will be due and payable periodically based on the applicable interest rate and related interest period. Loans under the term loan agreement are secured by a lien on our assets, including the capital stock and assets of Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P. and the approximately 36.4 million common units of ETP that we and our subsidiaries own. The term loan agreement also contains customary representations and warranties (including those relating to corporate organization and authorization, compliance with laws, absence of defaults and litigation).
The term loan agreement also includes a number of mandatory prepayment events. Loans under the term loan agreement must, subject to specified exceptions, be repaid with (a) 100% of net cash proceeds of all non-ordinary course asset sales if our leverage ratio is greater than or equal to 4.0:1.0; (b) 50% of net cash proceeds of all non-ordinary course asset sales if our leverage ratio is less than 4.0:1.0 and greater than or equal to 3.0:1.0; (c) 100% of excess cash flow if our leverage ratio is greater than or equal to 6.0:1.0; (d) 50% of excess cash flow if our leverage ratio is less than 6.0:1.0 and greater than or equal to 4.5:1.0; (e) 25% of excess cash flow if our leverage ratio is less than 4.5:1.0 and greater than or equal to 3.5:1.0; and (f) cash proceeds from public offerings of our limited partnership interests, including our initial public offering, until we have repaid an aggregate of $200.0 million.
The term loan agreement contains affirmative covenants relating to, among other things: delivery of financial statements and other reports, including compliance certificates and notice of specified events; maintenance of existence; payment of taxes and claims; maintenance of property and insurance; lender inspection rights; compliance with law, including environmental laws; subsidiary guarantee and security obligations; further assurances; use of proceeds; separateness of ETP; payment of contractual or debt obligations; and subsidiaries. The term loan agreement also contains negative covenants relating to, among other things: incurrence of indebtedness; liens; restricted payments; restrictions on subsidiary distributions; investments; fundamental changes; dispositions of assets; acquisitions; capital expenditures; sale and lease-back transactions; transactions with affiliates; conduct of business; changes in fiscal year or in tax status; and amendments or waivers of certain agreements or material contracts. The negative covenant related to the incurrence of indebtedness prohibits us from incurring more than $100.0 million of other indebtedness, in addition to the indebtedness under this term loan facility. The term loan agreement provides for events of default upon the occurrence of, among other things: failure to make payments on principal and interest under the term loan agreement; cross-defaults to other indebtedness; breach of covenants; breach of representations; bankruptcy; certain judgments; dissolution of our general partner; default under employee benefit plans; change of control; unenforceability or repudiation of guarantees or collateral documents; the leverage ratio of ETP exceeding the lower of 5.25:1.0 and the applicable leverage ratio set forth in the ETP Credit Agreement; to the extent available to us, failure to deliver a copy of the compliance certificate delivered under the ETP Credit Agreement; and creation of restrictions on the ability of ETP and its subsidiaries to make distributions. The term loan facility also contains financial covenants which are described in detail below.
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The financial covenants contained in the term loan agreement include a consolidated leverage ratio test (not to exceed a ratio ranging from 6.25:1.0 to 4.0:1.0), a consolidated interest coverage ratio test (not to be less than a ratio ranging from 2.25:1.0 to 3.0:1.0) and a value to loan ratio (not to be less than 2.0:1.0). Our leverage ratio as of the last day of any fiscal quarter, beginning with the fiscal quarter ending August 31, 2005, cannot exceed the correlative ratio indicated below:
| Period |
Ratio | |
| August 31, 2005 |
6.25:1.00 | |
| November 30, 2005 |
6.00:1.00 | |
| February 28, 2006 |
6.00:1.00 | |
| May 31, 2006 |
5.50:1.00 | |
| August 31, 2006 |
5.50:1.00 | |
| November 30, 2006 |
5.00:1.00 | |
| February 28, 2007 |
5.00:1.00 | |
| May 31, 2007 |
4.50:1.00 | |
| August 31, 2007 |
4.50:1.00 | |
| November 30, 2007 |
4.00:1.00 | |
| February 29, 2008 |
4.00:1.00 | |
| May 31, 2008 |
4.00:1.00 |
Our interest coverage ratio as of the last day of any fiscal quarter, beginning with the fiscal quarter ending August 31, 2005, cannot be less than the correlative ratio indicated below:
| Period |
Ratio | |
| August 31, 2005 |
2.25:1.00 | |
| November 30, 2005 |
2.50:1.00 | |
| February 28, 2006 |
2.50:1.00 | |
| May 31, 2006 |
2.50:1.00 | |
| August 31, 2006 |
2.75:1.00 | |
| November 30, 2006 |
2.75:1.00 | |
| February 28, 2007 |
2.75:1.00 | |
| May 31, 2007 |
2.75:1.00 | |
| August 31, 2007 |
3.00:1.00 | |
| November 30, 2007 |
3.00:1.00 | |
| February 29, 2008 |
3.00:1.00 | |
| May 31, 2008 |
3.00:1.00 |
Finally, we cannot permit the value to loan ratio as of any date to be less than 2.00:1.00.
If we were to fail the total leverage ratio covenant, breach any other covenant contained in the term loan agreement, or otherwise are in default under the term loan agreement, the restricted payment covenant in the term loan agreement restricts our ability to pay distributions during the period in which the default remained uncured. Upon the occurrence of a default, we would seek a waiver from our lenders under this facility; however, if we were unable to obtain a waiver from our lenders and the default remained uncured after any applicable grace period, the lenders representing more than 50% of the loans outstanding under the term loan agreement would be entitled to declare all outstanding loans immediately due and payable.
We believe that our future cash expected to be provided by operating activities, loans from the term loan agreement, and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements through at least the maturity date of our term loan agreement.
Credit Facility. Concurrently with the closing of this offering, we expect to enter into a new credit facility of up to $100 million. We anticipate that the indebtedness under this facility will bear interest at a rate of LIBOR plus basis points per annum. In addition, we anticipate that this term loan facility will contain various covenants
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limiting our ability to incur indebtedness, grant liens and make distributions. We also anticipate that this new credit facility will contain covenants requiring us to maintain specified financial ratios. After this offering, we expect to have borrowings of approximately $ million outstanding under this facility.
Energy Transfer Partners
ETP’s indebtedness consists of $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012 and a Revolving Credit Facility that allows for borrowings of up to $800.0 million through January 18, 2010. ETP also currently maintains a separate credit facility for HOLP, one of its principal operating subsidiary partnerships. Prior to January 18, 2005, ETP maintained a separate credit facility for ETC OLP, ETP’s other principal operating subsidiary partnership which was paid off using net proceeds received from ETP pursuant to its offering of 5.95% Senior Notes due 2015. The terms of the indebtedness of ETP and its two operating partnerships are described in more detail below. Failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact the ability of ETP and its subsidiaries to incur additional debt and its ability to pay distributions. Each of the borrowers is required to measure these financial tests and covenants quarterly and, as of May 31, 2005, they were in compliance or had no continuing defaults with all financial requirements, tests, limitations, and covenants related to financial ratios under their existing credit agreements.
Senior Notes.
On January 18, 2005, in a Rule 144A private placement offering, ETP issued $750.0 million in aggregate principal amount of its 5.95% Senior Notes due on February 1, 2015 (the “2015 Unregistered Notes”). ETP recorded a discount of $8.7 million in connection with the issuance of the 2015 Unregistered Notes. The net proceeds of approximately $741.0 from the sale of the 2015 Unregistered Notes were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. On July 29, 2005, ETP completed the exchange of the notes for substantially similar notes registered under the Securities Act of 1933, as amended.
On July 29, 2005, in a Rule 144A private placement offering, ETP issued $400.0 million in aggregate principal amount of its 5.65% Senior Notes due on February 1, 2015 (the “2012 Unregistered Notes” and together with the 2015 Unregistered Notes, the “ETP Senior Notes”). ETP recorded a discount of $ million in connection with the issuance of the 2012 Unregistered Notes. The net proceeds of approximately $397.1 from the sale of the 2012 Unregistered Notes were used to retire a portion of ETP’s outstanding indebtedness under its revolving credit facility, to fund ETP’s recently announced capital expansion projects and for general partnership purposes.
The ETP Senior Notes represent senior unsecured obligations of ETP and rank equally with all other existing and future unsecured and unsubordinated indebtedness of ETP. The ETP Senior Notes are jointly and severally guaranteed by ETC OLP and all of the direct and indirect wholly owned and majority-owned subsidiaries of ETC OLP. The subsidiary guarantees rank equally in right of payment with all of the existing and future unsubordinated indebtedness of ETP’s guarantor subsidiaries. The ETP Senior Notes and each guarantee will effectively rank junior to any future indebtedness of ETP and its subsidiary guarantors that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes will effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries that are not subsidiary guarantors.
The ETP Senior Notes were issued under an indenture containing covenants, which include covenants that restrict ETP’s ability to, subject to certain exceptions, incur debt secured by liens, engage in sale and leaseback transactions, or merge or consolidate with another entity or sell substantially all of its assets.
Revolving Credit Facility. On January 18, 2005, ETP entered into a $700.0 million Revolving Credit Facility available through January 18, 2010. Effective June 2, 2005, the ETP Revolving Credit Facility was amended to increase the borrowing capacity from $700.0 million to $800.0 million. Amounts borrowed under the
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ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. As of May 31, 2005, $443.0 million was outstanding under the ETP Revolving Credit Facility. There were also $0.8 million in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing under the ETP Revolving Credit Facility. The ETP Revolving Credit Facility also offers a swingline loan option with the maximum borrowing of $30.0 million and a daily rate based on the London market. As of May 31, 2005, $30.0 million was outstanding under the swingline loan option. Total amount available under the ETP Revolving Credit Facility as of May 31, 2005 was $256.2 million after deducting $0.8 million in letters of credit.
The ETP Revolving Credit Facility requires that, on the last day of each of ETP’s fiscal quarters, the ratio of ETP’s Consolidated Funded Debt (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to ETP’s Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must be no greater than 4.50 to 1.00 except that, on the last day of any fiscal quarter in which ETP or its subsidiaries makes an acquisition with a purchase price of $50.0 million or more, such ratio must be no greater than 5.0 to 1.0. You should note that ETP’s Consolidated Debt to ETP’s Consolidated EBITDA for purposes of ETP’s financial covenants includes only the operations of ETP and its subsidiaries and excludes our operations and those of our subsidiaries that are not subsidiaries of ETP. In addition, this facility requires that the ratio of ETP’s Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to ETP’s Consolidated Interest Expense (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must not be less than 3.0 to 1.0. ETP satisfied its leverage ratio covenants for the fiscal year ended August 31, 2004 and for the nine months ended May 31, 2005 and therefore was able to make the cash distributions at the levels it distributed during these periods.
ETC OLP and its designated subsidiaries act as guarantors of the debt obligations of ETP under the ETP Revolving Credit Facility. If ETP were to default on the ETP Revolving Credit Facility, ETC OLP and its designated subsidiaries would be responsible for full repayment of the debt obligations of ETP under the ETP Revolving Credit Facility. The ETP Revolving Credit Facility is unsecured and the lenders thereunder have equal rights to holders of ETP’s other current and future unsecured senior debt.
HOLP Facilities
Working Capital Facility. Effective March 31, 2004, HOLP entered into the third amended and restated credit agreement, which includes a $75.0 million senior revolving working capital facility available through December 31, 2006 (the “HOLP Working Capital Facility”). Amounts borrowed under the working capital facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.00% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. HOLP completed the 30-day clean down requirement under the HOLP Working Capital Facility on June 14, 2005. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Working Capital Facility. As of May 31, 2005, the HOLP Working Capital Facility had a balance outstanding of $6.5 million and $1.0 million of outstanding letters of credit. A $5.0 million letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of its working capital facility. Letter of credit exposure plus the working capital loan cannot exceed the $75.0 million maximum working capital facility.
Acquisition Facility. The third amended and restated credit agreement also includes a $75.0 million senior revolving acquisition facility that is available through December 31, 2006 (the “HOLP Acquisition Facility”). Amounts borrowed under the HOLP Acquisition Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.715% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts,
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equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Acquisition Facility. As of May 31, 2005, the HOLP Acquisition Facility had a balance outstanding of $41.0 million.
Senior Secured Notes. In connection with its initial public offering, on June 25, 1996, HOLP entered into a Note Purchase Agreement whereby HOLP issued $120 million principal amount of 8.55% Senior Secured Notes (the “HOLP Notes”) with institutional investors. Interest is payable semi-annually in arrears on each December 31 and June 30. The HOLP Notes have a final maturity of June 30, 2011, with ten equal mandatory repayments of principal, which began on June 30, 2002. At May 31, 2005, $84 million of principal debt was outstanding under the HOLP Notes.
On November 19, 1997, HOLP entered into a Note Purchase Agreement that provided for the issuance of up to $100 million of senior secured promissory notes (the “HOLP Medium Term Note Program”) if certain conditions were met. An initial placement of $32 million (Series A and B), at an average interest rate of 7.23% with an average 10-year maturity, was completed at the closing of the Medium Term Note Program. Interest is payable semi-annually in arrears on each November 19 and May 19. An additional placement of $15 million (Series C, D and E), at an average interest rate of 6.59% with an average 12-year maturity, was completed in March 1998. Interest is payable on Series C and D semi-annually in arrears on each September 13 and March 13. The proceeds of the placements were used to refinance amounts outstanding under HOLP Acquisition Facility. No future placements are permitted under the unused portion of the HOLP Medium Term Note Program. During the fiscal year ended August 31, 2003, HOLP used $3.9 million and $5.0 million of the proceeds from the issuance by Heritage of 1,610,000 of common units to retire the balance of the Series D and Series E Senior Secured Notes, respectively. At May 31, 2005, $28.7 million of principal debt was outstanding under the HOLP Medium Term Note Program.
On August 10, 2000, HOLP entered into a Note Purchase Agreement (the “HOLP Senior Secured Promissory Notes”) that provided for the issuance of up to $250 million of fixed rate senior secured promissory notes if certain conditions were met. An initial placement of $180 million (Series A through F) at an average rate of 8.66% with an average 13-year maturity, was completed in conjunction with the merger with U.S. Propane. Interest on the HOLP Senior Secured Promissory Notes is payable quarterly. The proceeds were used to finance the transaction with U.S. Propane and retire a portion of existing debt. On May 24, 2001, HOLP issued an additional $70 million (Series G through I) of the Senior Secured Promissory Notes to a group of institutional lenders with 7-, 12- and 15-year maturities and an average coupon rate of 7.66%. HOLP used the net proceeds from the HOLP Senior Secured Promissory Notes to repay the balance outstanding under HOLP’s Acquisition Facility and to reduce other debt. Interest is payable quarterly. During the fiscal year ended August 31, 2003, HOLP used $7.5 million and $19.5 million of the proceeds from the issuance by Heritage of 1,610,000 of common units to retire a portion of the Series G and Series H Senior Secured Promissory Notes, respectively. At May 31, 2005, $204.4 million of principal debt was outstanding under the HOLP Senior Secured Promissory Notes.
Covenants Related to HOLP Credit Agreements. The Note Purchase Agreements for each of the HOLP Notes, the HOLP Medium Term Note Program and the HOLP Senior Secured Promissory Notes, and the HOLP’s bank credit facilities contain customary restrictive covenants applicable to HOLP, changes in ownership of HOLP, including limitations on the level of additional indebtedness, creation of liens, and substantial disposition of assets. These covenants require HOLP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined in the Note Purchase Agreements of HOLP) of not more than 4.75 to 1.00 and Consolidated EBITDA to Consolidated Interest Expense (as defined in the Note Purchase Agreements) of not less than 2.25 to 1.00. For purposes of calculating the ratios under the Note Purchase Agreements, Consolidated EBITDA is based upon HOLP’s EBITDA, as adjusted, during the most recent four quarterly periods and modified to give pro forma effect for acquisitions and divestures made during the test period, and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. The Note Purchase Agreements also provide that HOLP may declare, make, or incur a liability to
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make, a restricted payment during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed its Available Cash (as defined in the Note Purchase Agreements) with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payment; and (c) HOLP’s restricted payments are not greater than the product of HOLP’s Percentage of Aggregate Partner Obligations (as defined in the Note Purchase Agreements). The Note Purchase Agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the HOLP Notes. In addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the HOLP Notes, Available Cash is required to reflect a reserve equal to 25%, 50% and 75%, respectively, of the principal amount to be repaid on such payment dates.
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Notes, the HOLP Medium Term Notes, and the HOLP Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. On May 31, 2004, the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.
ETC OLP Facilities
In January 2005, ETC OLP repaid the entire amounts borrowed under its $725.0 million term loan facility and its $225.0 million revolving credit facility using net proceeds received from ETP pursuant to ETP’s private placement of $750.0 million of 5.95% Senior Notes due 2015.
Cushion Gas Loan. In January 2005, ETC OLP entered into a short-term loan agreement with us, whereby ETC OLP borrowed approximately $174.6 million in connection with the acquisition of the Houston Pipeline System to purchase from the sellers the working gas inventory of natural gas stored in the Bammel storage facility. The six-month note provides for the payment of interest based on the Eurodollar Rate plus 3.0% per annum. The loan was repaid in full during the quarter ended May 31, 2005 and the unamortized debt issuance costs were written off and accounted for as loss on extinguishment of debt in the consolidated statements of operations for the three and nine months ended May 31, 2005.
ETE—Long-Term Debt and Contractual Obligations
The following table summarizes ETE’s long-term debt and other contractual obligations as of August 31, 2004:
| Payments Due by Period | |||||||||||||||
| Contractual Obligations |
Total |
Less Than 1 Year |
1–3 Years |
3–5 Years |
More Than 5 Years | ||||||||||
| (in thousands) | |||||||||||||||
| Long-term debt |
$ | 1,102,392 | $ | 31,234 | $ | 111,364 | $ | 813,665 | $ | 146,129 | |||||
| Interest on long-term debt (a) |
257,508 | 60,407 | 110,075 | 46,946 | 40,080 | ||||||||||
| Operating lease obligations |
13,437 | 4,794 | 5,152 | 2,863 | 628 | ||||||||||
| Totals |
$ | 1,373,337 | $ | 96,435 | $ | 226,591 | $ | 863,474 | $ | 186,837 | |||||
| (a) | Interest expense includes fixed rate debt on the assumed outstanding principal and interest on variable rate debt at the current interest rates on the bank credit facilities. See Note 5—“Working Capital Facility and Long-Term Debt” to the Consolidated Financial Statements beginning on Page F-19 of this prospectus for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt. |
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FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require us to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the our financial statements.
SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment.” In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. We do not expect SFAS 123R to have a material impact on our consolidated results of operations, cash flows or financial position.
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on our consolidated results of operations, cash flows or financial position.
SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-13 (“EITF 03-13”), “Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. We accounted for the sale of our discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.
EITF Issue No. 03-6 (“EITF 03-6”). “Participating Securities and the Two-Class method under FASB Statement No. 128.” EITF 03-6 requires the calculation of net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings, as if all of the earnings for the period had been distributed. In periods with undistributed earnings above certain levels, the calculation according to the two-class method results in an increased allocation of undistributed earnings to the
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general partner of ETP and dilution of the earnings to the limited partners. In periods that may have year-to-date net losses, the allocation of the net losses to the limited partners and the general partner of ETP will be determined based on the same allocation basis specified in the ETP partnership agreement that would apply to periods in which there were no undistributed earnings. ETP follows the requirements of EITF 03-6 in calculating its net earnings per limited partner unit and EITF 03-6 is not applicable to ETE.
In January of 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51 (FIN 46). In December 2003, the FASB issued FIN 46R, which clarified certain issues identified in FIN 46. FIN 46R requires an entity to consolidate a variable interest entity if the entity is designated as the primary beneficiary of that variable interest entity even if the entity does not have a majority of voting interest. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception of any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after March 15, 2004. The implementation of FIN 46 did not have an impact on our financial position or results of operations.
As of August 31, 2004 and 2003, we owned various unconsolidated entities in which our share of the unconsolidated entities ranges from 49% to 50%. We account for our investments under the equity method of accounting as prescribed by APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. We do not control these entities, and each partner shares in all profits and losses equal to their respective share in the entities. There are no limits on the exposure to losses or on the ability to share in returns. Based on the analysis performed, we are not the primary beneficiary of the entities, and as a result, will not consolidate the entities but will continue to account for the investments in these entities under the equity method.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (SFAS 150). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS 150 as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We adopted the provisions of SFAS 150 as of September 1, 2003. The adoption did not have a material impact on our consolidated financial position or results of operations.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Note 3—“Summary of Significant Accounting Policies and Balance Sheet Detail” to the Consolidated Financial Statements beginning on page F-19 of this prospectus. ETP believes the following are its critical accounting policies:
Revenue Recognition. ETP recognizes revenue for sales or services at the time the natural gas or NGLs are delivered or at the time the service is performed. Transportation capacity payments are recognized when earned in the period the capacity is made available.
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Sales of propane, propane appliances, parts, and fitting are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor is recognized upon completion of the service and tank rent is recognized ratably over the period it is earned. Shipping and handling revenues are included in the price of propane charged to customers, and thus are classified as revenues.
Marketable Securities. ETP has marketable securities that are classified as available-for-sale. Unrealized holding losses occur as a result of declines in the market value of its holdings. The fair market value of these holdings is determined based upon the market price of the securities, which are publicly traded securities. Based on the performance of the securities over the preceding nine-month period, ETP reviewed the fair market value to determine if an other-than temporary impairment should be recorded.
Impairment of Long-Lived Assets and Goodwill. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
In order to test for recoverability, ETP must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas and propane supply, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other midstream companies, including major energy producers. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.
Stock Based Compensation Plans. ETP accounted for its stock compensation plans following the fair value recognition method. This method was adopted as we believe it is the preferable method of accounting for stock based compensation. Please see Note 3—“Summary of Significant Accounting Policies and Balance Sheet Detail” to the Consolidated Financial Statements beginning on page F-19 of this prospectus for additional information about this adoption.
Property, Plant, and Equipment. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures also include capital expenditures made to connect additional wells to ETP’s systems in order to maintain or increase throughput on its existing assets. Growth or expansion capital expenditures are capital expenditures made to expand the existing operating capacity of ETP’s assets, whether through construction or acquisition. ETP treats repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as it incurs them. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful life ranging from 5 to 65 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. ETP does not anticipate future changes in the estimated useful life of its property, plant, and equipment.
Amortization of Intangible Assets. ETP calculates amortization using the straight-line method over periods ranging from 2 to 15 years. ETP uses amortization methods and determines asset values based on management’s best estimate using reasonable and supportable assumptions and projections. Changes in the amortization methods or asset values could have a material effect on ETP’s results of operations. ETP does not anticipate future changes in the estimated useful lives of its intangible assets.
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Fair Value of Derivative Commodity Contracts. ETP utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of commodity forward, future, swaps, options and certain basis contracts as cash flow hedging instruments. Many of these contracts are not accounted for as hedges, but are marked to fair value on the income statement, in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” In its retail propane business, ETP classifies all gains and losses from these derivative contracts entered into for risk management purposes as liquids marketing revenue in the consolidated statement of operations. On its contracts that are designated as cash flow hedging instruments in accordance with SFAS No. 133, the effective portion of the hedged gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the instrument settles. The ineffective portion of the gain or loss is reported in earnings immediately. ETP utilizes published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. The values have been adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under existing market conditions. Changes in the methods used to determine the fair value of these contracts could have a material effect on ETP’s results of operations. ETP does not anticipate future changes in the methods used to determine the fair value of these derivative contracts.
Gain on issuances of subsidiary units. We have elected not to record gains arising from issuances of units by ETP as permitted by SEC Staff Accounting Bulletin No. 51. If ETP issues units at a price less than our carrying value per unit, we assess whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. We did not recognize any impairments related to the issuance of ETP units during the year ended August 31, 2004 or the eleven months ended August 31, 2003.
Natural Gas Imbalances. ETP records imbalance receivables and payables when a customer delivers more or less gas into ETP’s pipelines than they take out. ETP primarily estimates the value of its imbalances at prices representing the value of the commodity at the end of the accounting reporting period. Changes in natural gas prices may impact its valuation. Based on ETP’s net receivable position of $6.1 million as of August 31, 2004, a change in natural gas prices of 10 percent could positively or negatively affect its results of operations by $0.6 million.
Volume Measurement. ETP records amounts for natural gas gathering and transportation revenue, liquid transportation and handling revenue, natural gas sales and natural gas purchases, and the sale of production based on volumetric calculations. Variances resulting from such calculations are inherent in ETP’s business.
Asset retirement obligation. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.
In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective. ETP has determined that it is obligated by contractual or regulatory requirements to remove assets or perform other remediation upon retirement of certain assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. ETP will record an asset retirement obligation in the periods in which it can reasonably determine the settlement dates.
Quantitative and Qualitative Disclosures about Market Risk
Market risk includes the risk of loss arising from adverse changes in market rates and prices. Our market risk results primarily from the operations of ETP. ETP faces market risk from commodity variations, risks related
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to interest rate variations, and to a lesser extent, credit risks. From time to time, it may utilize derivative financial instruments as described below to manage its exposure to such risks.
Commodity Price Risk
ETP is exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that it buys and sells and in its midstream, transportation and storage, and marketing activities. Derivative instruments are used to protect margins on natural gas purchases, sales, transportation, storage, and natural gas liquid sales. In ETP’s retail propane business, the market price of propane is often subject to volatile changes as a result of supply or other market conditions over which ETP has no control. In the past, price changes have generally been passed along to ETP’s propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to ETP during periods of high demand, it will at times purchase significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at ETP’s customer service locations and in major storage facilities and for future resale.
ETP uses a combination of financial instruments including, but not limited to, futures, price swaps, options and basis trades to manage its exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow ETP to protect its margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.
The use of financial instruments may expose ETP to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected, or (2) ETP’s counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that ETP engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, ETP is similarly protected against decreases in such prices for hedged transactions.
ETP manages its price risk related to future physical purchase or sale commitments for its producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance its future commitments and significantly reduce its risk to the movement in prices. However, unbalanced positions can exist that expose ETP to commodity price risk. In addition, ETP is subject to counterparty risk for both the physical and financial contracts. ETP accounts for such physical contracts under the “normal purchases and sales exception” in accordance with SFAS 133. In connection with the acquisition of the Houston Pipeline System, ETP acquired certain physical forward contracts that contain embedded options that the company has not designated as a normal purchase and sale nor were they designated as hedges under SFAS 133. These contracts are marked to market, along with the financial options that offset them, and are recorded in the statement of operations and on ETP’s consolidated balance sheet as a component of price risk management assets and liabilities.
In ETP’s midstream and transportation and storage segments, ETP accounts for certain of its derivatives as cash flow hedges under SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets and liabilities measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income (loss). The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income (loss) and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations.
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The following summarizes ETP’s open commodity derivative positions as of May 31, 2005. ETP’s counterparties to financial contracts include ABN Amro, BP Corporation, Sempra Energy Trading Corp., and Merrill Lynch Commodities.
| May 31, 2005: |
Commodity |
Notional Volume MMBTU |
Maturity |
Fair Value |
|||||||
| Basis Swaps IFERC/Nymex |
Gas | 117,304,500 | 2005 | $ | 3,167 | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 55,406,013 | 2006 | (4,198 | ) | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 1,800,000 | 2007 | (277 | ) | ||||||
| $ | (1,308 | ) | |||||||||
| Basis Swaps IFERC/Nymex |
Gas | 160,806,194 | 2005 | $ | (6,739 | ) | |||||
| Basis Swaps IFERC/Nymex |
Gas | 102,855,860 | 2006 | 5,530 | |||||||
| Basis Swaps IFERC/Nymex |
Gas | 15,290,500 | 2007 | 479 | |||||||
| $ | (730 | ) | |||||||||
| Swing Swaps IFERC |
Gas | 148,265,000 | 2005 | $ | 935 | ||||||
| Swing Swaps IFERC |
Gas | 65,150,000 | 2006 | (53 | ) | ||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2007 | — | |||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2008 | — | |||||||
| $ | 882 | ||||||||||
| Swing Swaps IFERC |
Gas | 158,495,000 | 2005 | $ | (41 | ) | |||||
| Swing Swaps IFERC |
Gas | 27,300,000 | 2006 | 133 | |||||||
| $ | 92 | ||||||||||
| Fixed Swaps |
Gas | 3,330,000 | 2005 | $ | 6,129 | ||||||
| Fixed Swaps |
Gas | 3,270,000 | 2006 | 8,919 | |||||||
| $ | 15,048 | ||||||||||
| Futures Nymex |
Gas | 37,652,500 | 2005 | $ | (9,338 | ) | |||||
| Futures Nymex |
Gas | 962,500 | 2006 | 9 | |||||||
| Futures Nymex |
Gas | 240,000 | 2007 | 224 | |||||||
| $ | (9,105 | ) | |||||||||
| Futures Nymex |
Gas | (72,001,000 | ) | 2005 | $ | 14,295 | |||||
| Futures Nymex |
Gas | (8,007,500 | ) | 2006 | (520 | ) | |||||
| $ | 13,775 | ||||||||||
| Options |
Gas | 5,210,000 | 2005 | $ | 6,946 | ||||||
| Options |
Gas | 10,000,000 | 2006 | 18,830 | |||||||
| Options |
Gas | 3,570,000 | 2007 | 8,032 | |||||||
| $ | 33,808 | ||||||||||
| Options |
Gas | (4,978,000 | ) | 2005 | $ | (19 | ) | ||||
| Options |
Gas | (10,730,000 | ) | 2006 | (166 | ) | |||||
| Options |
Gas | (4,300,000 | ) | 2007 | (281 | ) | |||||
| Options |
Gas | (732,000 | ) | 2008 | (406 | ) | |||||
| $ | (872 | ) | |||||||||
| Forward Contracts |
Gas | (5,210,000 | ) | 2005 | $ | (6,946 | ) | ||||
| Forward Contracts |
Gas | (10,000,000 | ) | 2006 | (18,830 | ) | |||||
| Forward Contracts |
Gas | (3,570,000 | ) | 2007 | (8,032 | ) | |||||
| $ | (33,808 | ) | |||||||||
| Forward Contracts |
Gas | 4,978,000 | 2005 | $ | 19 | ||||||
| Forward Contracts |
Gas | 10,730,000 | 2006 | 166 | |||||||
| Forward Contracts |
Gas | 430,000,000 | 2007 | 281 | |||||||
| Forward Contracts |
Gas | 732,000 | 2008 | 406 | |||||||
| $ | 872 | ||||||||||
| Barrels |
|||||||||||
| NGL Swaps |
Condensate | 15,000 | 2005 | $ | (179 | ) | |||||
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In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with our liquids marketing activity are accounted for using the mark-to-market method. Under the mark-to-market method of accounting, forwards, swaps, options, and storage contracts are reflected at fair value, and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. We follow the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as other revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. ETP attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. ETP also attempts to maintain balanced positions in its midstream and transportation and storage segments to protect ETP from the volatility in the energy commodities markets. However, net unbalanced positions can exist.
The notional amounts and terms of these financial instruments as of May 31, 2005 include fixed price payor for 207,857 barrels of propane and fixed price receiver of 285,000 barrels of propane. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure exposure to market or credit risks. The fair value of the financial instruments related to liquids marketing activities, as of May 31, 2005 was assets of $0.1 million and liabilities of $0.1 million.
On all transactions in which ETP is exposed to counterparty risk, ETP analyzes the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.
Sensitivity analysis
The table below summarizes ETP’s positions and values. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.
| May 31, 2005: |
Notional Volume MMBTU |
Fair Value |
Effect of Hypothetical 10% Change | ||||||
| (dollars in thousands) | |||||||||
| Futures Nymex |
41,153,500 | $ | 4,670 | $ | 29,349 | ||||
| Basis Swaps IFERC/Nymex |
104,442,041 | $ | (2,038 | ) | $ | 1,459 | |||
| Fix/Float Swaps |
6,600,000 | $ | 15,048 | $ | 4,695 | ||||
| Options |
1,960,000 | $ | 32,936 | $ | 11,929 | ||||
| Forward Contracts |
1,960,000 | $ | (32,936 | ) | $ | 11,929 | |||
| Crude Swap |
15,000 | $ | (179 | ) | $ | 78 | |||
Estimates related to ETP’s liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $0.3 million change in the market value of the contracts as there were approximately 77 thousand barrels of net unbalanced positions at May 31, 2005.
Interest Rate Risk
ETP is exposed to changes in interest rates, primarily as a result of its debt with floating interest rates and, in particular, its revolving credit facility. To the extent interest rates increase, its interest expense for its revolving debt will also increase. At May 31, 2005, ETP had $514.0 million of variable rate debt outstanding that is not hedged. A hypothetical change of 100 basis points in the underlying interest rate would have an effect of $5.2 million in increased interest expenses on an annual basis.
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On January 6, 2005, ETP entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to ETP’s anticipated issuance of $750.0 million in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $0.4 million which is recorded in accumulated other comprehensive income. The loss will be amortized over the term of the bonds as interest expense.
ETP also entered into various forward starting interest swaps from February 2005 through May 2005, in anticipation of the issuance of an additional bond offering in the third or fourth fiscal quarter of 2005. Due to certain market conditions, the bond offering was postponed until subsequent to May 31, 2005. Such agreements were designated as cash flow hedges of an anticipated transaction under SFAS 133. When the forward starting interest swaps settle and the anticipated bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. Certain forward starting interest swaps settled during the three months ended May 31, 2005 with a net $1.4 million receipt from the counterparties. Due to the timing of entering into the forward starting interest swaps and the anticipated bond issuance, $0.4 million was recorded as a reduction of interest expense in the three months ended May 31, 2005. Forward starting interest swaps with a notional amount of $400.0 million were outstanding as of May 31, 2005 and had a fair value of $4.2 million which was recorded as unrealized losses in accumulated other comprehensive income and a component of price risk management liabilities on the consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the period was a loss of $2.1 million and was reclassified from accumulated other comprehensive income and recorded as a component of interest expense during the three months ended May 31, 2005. A hypothetical change of 100 basis points on the notional amount of $400.0 million with a current fair value of $(4.2) million would have an effect of $34.1 million on the value of the swap.
ETP also has an interest rate swap with a notional amount of $75.0 million that matures in October 2005. Under the terms of the swap agreement, ETP will pay a fixed rate of 2.76% and will receive three-month LIBOR with a quarterly settlement. The interest rate swap is not accounted for as a hedge but receives mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the consolidated statement of operations.
ETP also has long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, ETP may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
Credit risk
ETP is diligent in attempting to ensure that its issues credit to only credit-worthy customers. However, ETP’s purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a small percentage of the total sales price. Therefore, a credit loss can be very large relative to ETP’s overall profitability.
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BUSINESS OF ENERGY TRANSFER EQUITY
We are a Delaware limited partnership. In addition to directly owning approximately 33% of Energy Transfer Partners’ outstanding common units as of the closing of this offering, we indirectly own and control the general partner of ETP, through which we hold the 2% general partnership interest and 50% of the incentive distribution rights in ETP. ETP is a publicly traded limited partnership that is primarily engaged in the natural gas midstream, transportation and storage business and also has a national retail propane business. As of July 31, 2005, ETP had an equity market capitalization of approximately $4.1 billion, making it the third largest publicly traded master limited partnership in equity market capitalization.
Our aggregate partnership interests in ETP consist of the following:
| • | the 2% general partner interest in ETP, which we hold through our ownership interests in Energy Transfer Partners GP; |
| • | 50% of the outstanding incentive distribution rights in ETP, which we hold through our ownership interests in Energy Transfer Partners GP; and |
| • | approximately 36.4 million common units of ETP (including 3.64 million common units of ETP which we will purchase at the closing of the offering), all of which are held directly by us. |
Our cash flows consist of distributions from ETP on these partnership interests. ETP is required by its partnership agreement to distribute all of its excess cash on hand at the end of each quarter after establishing reserves to provide for the proper conduct of ETP’s business or to provide for future distributions.
ETP has increased its quarterly distribution on its common units 16 times since its initial public offering in 1996. On September 2, 2005, ETP increased its distribution pursuant to $0.50 per unit per quarter for the quarter ended August 31, 2005 (or $2.00 per unit on an annualized basis). Under ETP’s current capital structure, a distribution of $0.50 per unit will result in a quarterly distribution to us of approximately $26.4 million in respect of our partnership interest in ETP. We forecast that our partnership interests in ETP will generate $105.4 million in cash to us for the fiscal year ending August 31, 2006, assuming a $2.00 per unit annual distribution.
The incentive distribution rights of ETP entitle Energy Transfer Partners GP, as holder of the incentive distribution rights, to receive the following percentages of cash distributed by ETP as the following target cash distribution levels are reached:
| • | 0% of all cash distributed in a quarter until $0.275 has been distributed in respect of each common unit; |
| • | 13.0% of all cash distributed in a quarter after $0.275 has been distributed in respect of each common unit of ETP for that quarter; |
| • | 23.0% of all cash distributed after $0.3175 has been distributed in respect of each common unit of ETP for that quarter; and |
| • | the maximum sharing level of 48.0% of all cash distributed after $0.4125 has been distributed in respect of each common unit of ETP for that quarter. |
As ETP has increased the quarterly cash distributions paid on its units, we have received increasing payouts on our interests in ETP. These increased cash distributions by ETP have caused the target cash distribution levels described above to be met, thereby increasing the amounts paid to Energy Transfer Partners GP as the owner of ETP’s incentive distribution rights. As a consequence, our cash distributions from ETP that are based on our
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indirect ownership of 50% of the incentive distribution rights have increased more rapidly than those based on our ownership of the general partner interest and ETP common units. Future growth in the distributions that we receive from ETP will not result from an increase in the sharing level associated with the incentive distribution rights as our incentive distribution rights currently participate at the maximum sharing level described above.
The graph set forth below shows hypothetical cash distributions payable in respect of our partnership interests, including the incentive distribution rights in ETP, across an illustrative range of annualized cash distributions per unit made by ETP. This information is based upon:
| • | ETP’s 110,534,514 common units outstanding as of the date of the closing of this offering; and |
| • | our ownership of (1) the 2% general partner interest in ETP, (2) 50% of the incentive distribution rights in ETP and (3) approximately 36.4 million common units of ETP. |
The graph illustrates the impact to us of ETP raising or lowering its per unit distribution of available cash from operating surplus from the current quarterly distribution of $0.50 per unit, or $2.00 per unit on an annualized basis. This information is presented for illustrative purposes only, is not intended to be a prediction of future performance and does not attempt to illustrate the impact that changes in our business, including changes that may result from changes in interest rates, changes in natural gas prices, changes in general economic conditions, or the impact of any future acquisitions or expansion projects, will have on our performance.
The aggregate amount of ETP’s cash distributions to us will vary depending on several factors, including ETP’s total outstanding partnership interests on the record date for the distribution, the aggregate cash distributions made by ETP and the amount of ETP’s partnership interests we own. If ETP increases distributions to its unitholders, including us, we would expect to increase distributions to our unitholders, although the timing and amount of such increased distributions, if any, will not necessarily be comparable to the timing and amount of the increase in distributions made by ETP. In addition, the level of distributions we receive may be affected by the various risks associated with an investment in us and the underlying business of ETP. Please read “Risk Factors.”
We intend to pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from our distributions, less certain reserves for expenses and other uses of cash, including:
| • | the expenses associated with being a public company and other general and administrative expenses; |
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| • | interest expense related to any current and future indebtedness; |
| • | expenditures to maintain or, at our election, to increase our ownership interest in ETP; |
| • | the payment of an annual management fee of $500,000 to our general partner and the reimbursement at its expenses incurred on our behalf; and |
| • | reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions. |
Based on the current cash distribution policy of ETP, as well as our expected level of expenses and reserves that our general partner believes prudent to maintain, we expect that our initial quarterly distribution rate will be $0.175 per common unit. If ETP is successful in implementing its business strategy and increasing distributions to its limited partners, we would generally expect to increase distributions to our unitholders, although the timing and amount of any such increased distributions will not necessarily be comparable to the timing and amount of increased ETP distributions. We expect to pay a prorated distribution for the period between the consummation of our initial public offering and the end of the first fiscal quarter during which we become a publicly traded partnership. However, we cannot assure you that any distributions will be declared or paid. We expect to make a distribution to our existing owners on or about January 14, 2006 with cash we receive from ETP with respect to its operations for the quarter ending November 30, 2005. You will not participate in this distribution. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”
Our common units and ETP’s common units are unlikely to trade in simple relation or proportion to one another. Instead, while the trading prices of our common units and ETP’s common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:
| • | with respect to ETP distributions, ETP’s common unitholders have a priority over our incentive distribution rights in ETP; |
| • | we participate in ETP’s general partner’s distributions and ETP’s incentive distribution rights, and ETP’s common unitholders do not; and |
| • | we may enter into other businesses separate from ETP or any of its affiliates. |
Our primary business objective is to increase our cash distributions to our unitholders by actively assisting ETP in executing its business strategy. We intend to support ETP in implementing its business strategy by assisting ETP in identifying, evaluating, and pursuing growth opportunities. In the future, we may also support the growth of ETP through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
ETP’s primary objective is to increase the level of its cash distributions over time by pursuing a business strategy that is currently focused on growing its intrastate natural gas midstream business (including transportation, gathering, compression, treating, processing, storage and marketing) and its national propane business through, among other things, pursuing construction and expansion opportunities relating to its existing infrastructure and acquiring additional businesses or assets.
ETP has grown significantly through acquisitions and through internal growth projects. The significant acquisitions and internal construction projects that ETP has completed beginning in January 2004 include:
| • | Energy Transfer Transactions. In January 2004, in a series of related transactions, the midstream and transportation operations of La Grange Acquisition, L.P. were combined with the retail propane |
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| operations of Heritage Propane Partners, L.P., a publicly traded limited partnership. These transactions, which we refer to as the “Energy Transfer Transactions,” were valued at approximately $1.0 billion. Subsequent to these transactions, the combined partnership’s name was changed to Energy Transfer Partners, L.P. |
| • | ET Fuel System. In June 2004, ETP acquired the midstream natural gas assets of TXU Fuel Company (now referred to as the ET Fuel System) from TXU Corp. for approximately $500 million. The ET Fuel System is comprised of approximately 2,000 miles of intrastate natural gas pipelines and related natural gas storage facilities that serve some of the most active natural gas drilling areas in Texas and provide direct access to power plants and interconnects with other intrastate and interstate pipelines that serve major markets. |
| • | East Texas Pipeline. In June 2004, ETP completed the construction of the Bossier Pipeline (now referred to as the East Texas Pipeline). The East Texas Pipeline is a 78-mile natural gas pipeline that provides transportation from the Bossier Sands drilling area in east and north central Texas to ETP’s Southeast Texas System. This pipeline cost approximately $71.4 million to construct. |
| • | Texas Chalk and Madison Systems. In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Energy Corporation for approximately $65.0 million. These systems consist of approximately 1,800 miles of gathering and mainline pipelines, four natural gas treating facilities and a natural gas processing facility located in central Texas near our existing gathering and processing assets. |
| • | Houston Pipeline System. In January 2005, ETP acquired the Houston Pipeline System from American Electric Power Company, Inc. for approximately $825.0 million plus $174.0 million in natural gas inventory, subject to working capital adjustments. This system is comprised of six main transportation pipelines, three market area loops and the largest natural gas storage facility in Texas. |
| • | Fort Worth Basin. In May 2005, ETP completed the construction of the Fort Worth Basin Pipeline, a 55-mile pipeline that provides transportation for natural gas production from the Barnett Shale producing area in north central Texas to ETP’s North Texas Pipeline. This pipeline cost approximately $53.0 million to construct. |
Through these acquisitions and internal growth projects, ETP has created an integrated natural gas transportation and storage system in Texas that facilitates the movement of natural gas from all of the significant natural gas producing areas in Texas to major metropolitan areas in Texas, including Dallas, Houston, Austin and San Antonio, as well as major market hubs and interstate pipelines that transport natural gas to other areas in the United States. This integrated system provides significant opportunities for additional internal growth projects that we believe will generate substantial returns on invested capital without the material execution and commercial risks typically associated with external projects. ETP recently announced approximately $500 million of capital expenditures for internal growth projects during the next 12 to 24 months for the two internal growth projects described below.
ETP’s recently announced major expansion projects involve several pipeline projects that are expected to increase pipeline transportation access for natural gas producers in the Bossier Sands and Barnett Shale basins in east and north Texas to various markets throughout Texas as well as to markets in the eastern United States through interconnects with other intrastate and interstate pipelines. The larger of the two expansion projects is expected to involve the construction of approximately 264 miles of pipeline and the addition of approximately 40,000 horsepower of compression at a cost of approximately $454 million. The expansion project will continue the integration of several pipeline systems and natural gas storage facilities, including the integration of ETP’s Katy Pipeline and its Southeast Texas System with the recently acquired ET Fuel System and Houston Pipeline System. This expansion project is supported by a 10-year agreement with XTO Energy pursuant to which XTO Energy has agreed to transport specified volumes of natural gas on an annual basis and is entitled to transport additional volumes under similar terms. Under the agreement with XTO Energy, ETP receives fixed reservation revenues based on XTO Energy’s contracted
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volumes. The remaining capacity will be offered to other shippers on a non-priority basis. This expansion project includes:
| • | the construction of a 36-inch pipeline from the intersection of ETP’s Fort Worth Basin Pipeline and its North Texas Pipeline near Cleburne, Texas to Central Freestone County; |
| • | the construction of a 42-inch pipeline from Central Freestone County to ETP’s Texoma Pipeline (which is part of its Houston Pipeline System); |
| • | the construction of a 30-inch pipeline from the intersection of these two new pipelines to ETP’s Katy-Bossier pipeline system, thereby allowing natural gas to be transported to the natural gas marketing hub near Katy, Texas; and |
| • | the construction of a 36-inch pipeline from the Texoma Pipeline to the natural gas marketing hub near Carthage, Texas. |
These pipelines are expected to have aggregate throughput capacity of approximately 1.6 bcf/d at full compression and will provide natural gas producers and shippers with significantly greater access to multiple natural gas markets. These construction projects are expected to take approximately 12 to 24 months to complete. However, portions of the projects are expected to generate cash flows in approximately 12 months.
ETP’s other major expansion project involves the construction, on a joint venture basis with Atmos Energy Corp., of a 30-inch pipeline in the north Fort Worth Basin area that will provide an additional outlet for natural gas from the Barnett Shale area to several market hubs.
Although our primary objective is to increase our cash distributions to our unit holders by assisting ETP achieve its business strategy, we may separately pursue opportunities to acquire businesses or construct assets.
How Our Partnership Agreement Terms Differ from those of Other Publicly Traded Partnerships
Although we are organized as a limited partnership, the terms of our partnership agreement differ from those of many other publicly traded partnerships. For example,
| • | our general partner is not entitled to incentive distributions (most publicly traded partnerships have incentive distribution rights which entitle the general partner to receive increasing percentages, commonly up to 50%, of the cash distributed in excess of a certain per unit distribution); |
| • | we do not have subordinated units (most publicly traded partnerships initially have subordinated units which (i) do not receive distributions until all common units receive the minimum quarterly distribution plus arrearages and (ii) convert to common units upon reaching specified distribution targets); |
| • | we will have Class B units issued under our Class B Unit Incentive Plan (see “Partnership Agreement Provisions Relating to Cash Distributions—Class B Units”); and |
| • | our general partner is not required to make additional capital contributions to us in connection with additional issuances of units by us (most general partners of publicly traded partnerships have a 2% general partner interest and are required to make additional capital contributions to the partnership in order to maintain their percentage general partner interest upon issuance of additional partnership interests by the partnership). |
To the extent that our general partner does not make additional capital contributions to us when we issue additional units, its general partner interest in us will be proportionately reduced. You should read the summaries in “Description of Our Common Units” and “Description of Our Partnership Agreement,” as well as Appendix A—Form of Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., for a more complete description of the terms of our partnership agreement.
We are not a party to any litigation.
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BUSINESS OF ENERGY TRANSFER PARTNERS
ETP is a rapidly-growing publicly traded limited partnership engaged in the natural gas midstream, transportation and storage business, with operations in Texas and Louisiana, and in the retail propane marketing business, with operations in 34 states. We describe the assets and operations of ETP in this prospectus because our indirect wholly owned subsidiary, Energy Transfer Partners GP, L.P., is the sole general partner of, and therefore controls, ETP. As a result, investors in us should consider ETP as our subsidiary, and its common unitholders as minority investors.
ETP’s midstream, transportation and storage business owns and operates approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to its gathering systems, 14 natural gas treating facilities and three natural gas storage facilities. ETP conducts its natural gas midstream, transportation and storage business through two segments, the midstream segment and the transportation and storage segment. The midstream segment focuses on the gathering, compression, treating, processing and marketing of natural gas, and its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. ETP’s transportation and storage segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through its Oasis Pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, its Houston Pipeline System and its recently completed Fort Worth Basin Pipeline, which are described below.
ETP is the fourth largest retail propane marketer in the United States, serving more than 700,000 customers from 315 customer service locations. Its propane operations extend from coast to coast, with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States.
ETP was originally formed as Heritage Propane Partners, L.P., which consummated its initial public offering in June 1996. In January 2004, the propane operations of Heritage were combined with the natural gas midstream and transportation operations of La Grange Acquisition conducted under the name Energy Transfer Company. We refer to this combination, along with the incurrence of debt and the issuance of equity securities of ETP in connection with that combination, as the Energy Transfer Transactions. In March 2004, the combined entity’s name was changed to Energy Transfer Partners, L.P.
For the year ended August 31, 2004, ETP had revenues of approximately $2.5 billion, operating income of approximately $145.5 million and net income of approximately $99.2 million.
Midstream, Transportation and Storage Operations. ETP’s midstream, transportation and storage assets, including the ET Fuel System acquired in June 2004, the midstream assets acquired from Devon Energy Corporation in November 2004 and the Houston Pipeline System acquired in January 2005, consist of ETP’s interests in approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are connected to its gathering systems with a total processing capacity of approximately 640 MMcf/d and 14 natural gas treating facilities with a total treating capacity of approximately 945 MMcf/d. ETP’s midstream, transportation and storage operations relating to these assets, which are primarily located in major natural gas producing regions of Texas, consist of the following:
| • | the gathering of natural gas from over 6,300 producing wells; |
| • | the compression of natural gas to facilitate its flow from the wells through ETC OLP’s gathering systems; |
| • | the treating and blending of natural gas to remove impurities such as carbon dioxide and hydrogen sulfide to ensure that the natural gas meets pipeline quality specifications; |
| • | the processing of natural gas to extract natural gas liquids, or NGLs; |
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| • | the sale of the pipeline quality natural gas, or “residue gas,” remaining after it is processed; |
| • | the sale of the NGLs to third parties at fractionation facilities where the NGLs are separated into their individual components, including ethane, propane, mixed butanes and natural gasoline; |
| • | the transportation of natural gas on the Oasis Pipeline, East Texas Pipeline, ET Fuel System and Houston Pipeline System to industrial end-users, independent power plants, utilities and other pipelines; |
| • | the storage of natural gas at the Bammel, Bethel and Bryson facilities; |
| • | the purchase for resale of natural gas from producers connected to its systems and from other third parties; and |
| • | natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. |
ETP’s midstream segment consists of the following:
| • | The Southeast Texas System, a 4,179-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. The system includes the La Grange processing plant and 10 treating facilities with an aggregate capacity of 740 MMcf/d. These treating facilities remove carbon dioxide and hydrogen sulfide from natural gas that is gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications. This system is connected to the Katy Hub through the 55-mile Katy Pipeline and is also connected to the Oasis Pipeline, as well as two power plants. |
| • | The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through ETP’s system to produce residue gas and NGLs. The plant has a processing capacity of approximately 240 MMcf/d. |
| • | ETP owns or has an interest in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, the Dorado System and the Chalkley Transmission System. On a combined basis, these assets have a capacity of approximately 600 MMcf/d. |
| • | Marketing operations through ETP’s producer services business, in which it markets the natural gas that flows through its assets, referred to as “on-system gas,” and attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as “off-system gas.” For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells the natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. |
Substantially all of ETP’s on-system marketing efforts involve natural gas that flows through either the Southeast Texas System, Oasis Pipeline, the Houston Pipeline System or ET Fuels System.
For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that do not have marketing operations. ETP develops relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. ETP believes that this business provides it with strategic insights and valuable market intelligence, which may impact its expansion and acquisition strategy.
ETP is exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that it buys and sells and in its midstream, processing and marketing activities. ETP uses a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage its exposure to market fluctuations in prices.
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ETP’s transportation and storage segment consists of the following:
| • | The Oasis Pipeline, a 583-mile natural gas pipeline that directly connects the Waha Hub to the Katy Hub. The Oasis Pipeline is primarily a 36-inch diameter natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline is currently flowing west-to-east with a current average throughput of approximately 1.18 Bcf/d. The Oasis Pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers. |
| • | The Oasis Pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing the Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System by: |
| • | providing ETP with the ability to bypass the La Grange processing plant when processing margins are unfavorable; |
| • | providing natural gas on the Southeast Texas system access to other third party supply and market points and interconnecting pipelines; and |
| • | allowing ETP to bypass its treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis Pipeline while continuing to meet pipeline quality specifications. |
| • | The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub, the Katy Hub and the Carthage Hub, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 1.3 Bcf/d of natural gas and total working storage capacity of 12.4 Bcf of natural gas. The ET Fuel System’s current average throughput is approximately 730 MMcf/d. Prior to ETP’s acquisition of it in June 2004, the ET Fuel System had been operated primarily as a natural gas transmission pipeline system to supply natural gas from various natural gas producing areas to electric generating power plants of TXU Corp. and its affiliates, which we collectively referred to as “TXU.” In connection with its acquisition of the ET Fuel System, ETP entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP, which we refer to as “TXU Shipper,” a subsidiary of TXU, to transport a minimum of 115.6 MMBtu per year, subject to certain adjustments as defined in the agreement, and TXU Shipper has elected, effective June 1, 2006, to reduce the minimum amount of natural gas that ETP is obligated to transport to not less than 100.0 MMBtu per year. ETP also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that were part of the ET Fuel System. The ET Fuel System operates ETP’s Bethel natural gas storage facility, with a working capacity of 6.4 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and ETP’s Bryson natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. |
| • | The East Texas Pipeline is a 78-mile natural gas pipeline that connects three treating facilities with ETP’s Southeast Texas System of which one treating facility is owned by ETP. This pipeline is the first phase of a multi-phased project that will service producers in East and North Central Texas providing access to the Katy Hub. The East Texas Pipeline expansion has initial capacity of over 400 MMcf/d and currently has over 500 MMcf/d of pipeline capacity contracted under long-term agreements with XTO Energy Inc. and other producers. |
| • | The Houston Pipeline System is comprised of approximately 4,200 miles of intrastate natural gas pipeline with an aggregate capacity of 2.4 Bcf/d, the underground Bammel storage reservoir and |
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| related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The Houston Pipeline System is well situated to gather gas in many of the major gas producing areas in Texas. The Houston Pipeline System has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contribute to the Houston Pipeline System’s overall ability to play an important role in the Texas natural gas markets. The Houston Pipeline System is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and its operation of the Bammel storage facility. The Bammel storage facility is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The field has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers. |
| • | The recently completed Fort Worth Basin Pipeline, which became operational on May 26, 2005, is a 55-mile, 24-inch natural gas pipeline that connects ETP’s existing pipelines in north Texas and provides transportation for natural gas production from the Barnett Shale producing area. The completion of the Fort Worth Basin Pipeline is the first part of ETP’s previously disclosed expansion program that was implemented to integrate ETP’s 36-inch Katy Pipeline and its Southeast Texas Pipeline assets with the ET Fuel System and the Houston Pipeline System. |
ETP’s goal is to increase unitholder distributions and the value of its common units. ETP believes that it has engaged, and will continue to engage, in a well-balanced plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of its existing assets.
ETP intends to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each of its common units. It believes that by pursuing independent operating and growth strategies for its midstream and transportation and propane businesses, it will be best positioned to achieve its objectives.
ETP expects that midstream and transportation acquisitions, such as its recent acquisitions of the ET Fuel System, the Devon midstream assets and the Houston Pipeline System, will be the primary focus of its acquisition strategy going forward, although it will also continue to pursue complementary propane acquisitions. ETP also anticipates that its midstream, transportation and storage business will provide internal growth projects of greater scale compared to those available in its propane business.
Midstream, Transportation and Storage Business Strategies
Enhance profitability of existing assets. ETP intends to increase the profitability of its existing asset base by adding new volumes of natural gas, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
Engage in construction and expansion opportunities. ETP intends to leverage its existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream services. These projects include expansion of existing systems, such as the East Texas Pipeline and the Fort Worth Basin project in North Texas, and construction of new facilities. ETP expects that these expansions will also lead to additional growth opportunities in this area.
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Increase cash flow from fee-based businesses. Fee-based margin represents approximately 76% of ETP’s midstream and transportation segments’ total gross margin for the year ended August 31, 2004. ETP generated approximately 29% of its gross margin during the year ended August 31, 2004 from fees charged for providing midstream services, including a transportation fee it charges its producer services business for natural gas that it transports on the Oasis Pipeline equal to the fee charged to third parties. This transportation fee accounted for 9% of total gross margin for this period. These fee-based services are dependent on throughput volume and are typically less affected by short-term changes in commodity prices. ETP intends to seek to increase the percentage of its midstream business conducted with third parties under fee-based arrangements in order to reduce exposure to changes in the prices of natural gas and NGLs. For example, ETP expects the fee-based contracts associated with the East Texas Pipeline, ET Fuel System and the Houston Pipeline System to significantly increase the fee-based component of its gross margins.
Growth through acquisitions. As demonstrated by its recent acquisitions of the ET Fuel System, the Devon midstream assets and the Houston Pipeline System, ETP intends to make strategic acquisitions of midstream, transportation and storage assets in its current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of ETP’s existing and acquired assets. ETP will also pursue midstream, transportation and storage asset acquisition opportunities in other regions of the U.S. with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. ETP believes that it will be well positioned to benefit from the additional acquisition opportunities likely to arise as a result of the ongoing divestiture of midstream assets by large industry participants.
Propane Business Strategies
Pursue internal growth opportunities. In addition to pursuing expansion through acquisitions, ETP has aggressively focused on high return internal growth opportunities at its existing customer service locations. ETP believes that by concentrating its operations in areas experiencing higher-than-average population growth, it is well positioned to achieve internal growth by adding new customers.
Growth through complementary acquisitions. ETP believes that its position as the fourth largest propane marketers provides it with a solid foundation to continue its acquisition growth strategy through consolidation. ETP believes that the fragmented nature of the propane industry will continue to provide opportunities for growth through the acquisition of propane businesses that complement its existing asset base. In addition to focusing on propane acquisition candidates in its existing areas of operations, ETP will also consider core acquisitions in other higher-than-average population growth areas in which it has no presence in order to further reduce the impact adverse weather patterns and economic downturns in any one region may have on its overall operations.
Maintain low-cost, decentralized operations. ETP focuses on controlling costs, and it attributes its low overhead costs primarily to its decentralized structure. By delegating all customer billing and collection activities to the customer service location level, as well as delegating other responsibilities to the operating level, ETP has been able to operate without a large corporate staff. In addition, ETP’s customer service location level incentive compensation program encourages employees at all levels to control costs while increasing revenues.
ETP believes that it is well positioned to compete in both the natural gas midstream, transportation and storage and propane industries based on the following strengths:
ETP’s enhanced access to capital and financial flexibility will allow it to compete more effectively in acquiring assets and expanding its systems. We expect that ETP’s recently obtained credit facility and other recent financing transactions will increase its financial flexibility and enhance its access to capital. We believe this will allow ETP to implement its operating strategies in a timely manner and more effectively compete in acquiring additional assets or expanding its existing systems.
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ETP’s experienced management team has an established reputation as highly-effective, strategic operators within ETP’s operating segments. In the past, the management teams of each of ETP’s operating segments have been successful in identifying and consummating strategic acquisitions to enhance its businesses. In addition, ETP’s management team has a substantial equity ownership in ETP and is motivated through performance-based incentive compensation programs to effectively and efficiently manage ETP’s business operations.
Midstream, Transportation and Storage Business Strengths
ETP has a significant presence in major natural gas supply areas. ETP has a significant market presence in each of its operating areas, which are located in major natural gas producing regions of the United States.
ETP’s assets provide marketing flexibility through its access to numerous markets and customers. ETP’s Oasis Pipeline combined with its Southeast Texas System provides its customers direct access to the Waha and Katy Hubs and to virtually all other market areas in the United States via interconnections with major intrastate and interstate natural gas pipelines. Furthermore, ETP’s Oasis Pipeline is tied directly or indirectly to a number of major power generation facilities in Texas as well as several industrial and utility end-users. With the acquisition of the ET Fuel System in June 2004, ETP has also enhanced its opportunities with additional power plants, industrial users, municipals, and co-operatives, and the added storage facilities add flexibility for fuel management services.
ETP’s Southeast Texas System has additional capacity, which provides opportunities for higher levels of utilization. ETP expects to connect new supplies of natural gas volumes by utilizing the available capacity on the Southeast Texas System. The available capacity also provides ETP with opportunities to extend the Southeast Texas System to additional natural gas producing areas, such as east Texas through the recently completed East Texas Pipeline.
ETP’s ability to bypass its La Grange processing plants reduces its commodity price risk. A significant benefit of ETP’s ownership of the Oasis Pipeline is that it can elect not to process natural gas at its La Grange processing plant when processing margins (or the difference between NGL sales prices and the cost of natural gas) are unfavorable. Instead of processing the natural gas, ETP is able to deliver natural gas meeting pipeline quality specifications by blending rich gas, or gas with a high NGL content, from the Southeast Texas System with lean gas, or gas with a low NGL content, transported on the Oasis Pipeline. This enables ETP to sell the blended natural gas for a higher price than it would have been able to realize upon the sale of NGLs if it had to process the natural gas to extract NGLs.
ETP’s acquisition of the Houston Pipeline System enables us to engage in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time. The Bammel natural gas storage facility, acquired when ETP purchased the Houston Pipeline System, is one of the largest natural gas storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 600 MMcf/d peak injection rate. Therefore, ETP is able to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin. In addition, the Bammel natural gas storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.
Propane Business Strengths
Geographically diverse retail propane network. ETP believes that its geographically diverse network of retail propane assets reduces its exposure to unfavorable weather patterns and economic downturns in any one geographic region, thereby reducing the volatility of its cash flows.
Experience in identifying, evaluating and completing acquisitions. ETP follows a disciplined acquisition strategy that concentrates on propane companies that (1) are located in geographic areas experiencing higher-than-average population growth, (2) provide a high percentage of sales to residential customers, (3) have a strong
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reputation for quality service, and (4) own a high percentage of the propane tanks used by their customers. In addition, ETP attempts to capitalize on the reputations of the companies it acquires by maintaining local brand names, billing practices and employees, thereby creating a sense of continuity and minimizing customer loss. ETP believes that this strategy has also helped to make it an attractive buyer for many propane acquisition candidates from the seller’s viewpoint.
Operations that are focused in areas experiencing higher-than-average population growth. ETP believes that its concentration in higher-than-average population growth areas provides a strong economic foundation for expansion through acquisitions and internal growth. ETP does not believe that it is more vulnerable than its competitors to displacement by natural gas distribution systems because the majority of ETP’s areas of operations are located in rural areas where natural gas is not readily available.
Low-cost administrative infrastructure. ETP’s propane operation is dedicated to maintaining a low-cost operating profile and has a successful track record of aggressively pursuing opportunities to reduce costs. Of the 2,589 full-time propane employees as of May 31, 2005, only 106, or approximately 4.1%, were general and administrative.
Decentralized operating structure and entrepreneurial workforce. ETP believes that its decentralized propane operations foster an entrepreneurial corporate culture by: (1) having operational decisions made at the customer service location and operating level, (2) retaining billing, collection and pricing responsibilities at the local and operating level, and (3) rewarding employees for achieving financial targets at the local level.
Midstream Natural Gas Industry Overview
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing and transportation and NGL fractionation and transportation and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
Natural gas has a widely varying quality and composition, depending on the field, the formation, or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, though most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline that may be removed by a number of processing methods. Most raw material produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas.
Demand for natural gas. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to increase by over 2.2% per annum, on average, to 27.1 Tcf by 2010, from an estimated 22.2 Tcf consumed in 2001, representing approximately 25% of all total end-user energy requirements by 2010. During the last five years, the United States has on average consumed approximately 22.6 Tcf per year, with average domestic production of approximately 19.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.
Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas bearing formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.
Natural gas compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce
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at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.
Natural gas treating. Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is high in carbon dioxide, hydrogen sulfide or other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.
Natural gas processing. Some natural gas produced by a well does not meet the quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.
Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.
Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Retail propane use falls into three broad categories: (1) residential applications, (2) industrial, commercial and agricultural applications and (3) other retail applications, including motor fuel sales. In ETP’s wholesale operations, it sells propane principally to large industrial end-users and other propane distributors.
Propane is extracted from natural gas at processing plants or separated from crude oil during the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is naturally colorless and odorless. An odorant is added to allow its detection. Like natural gas, propane is a clean burning fuel and is considered an environmentally preferred energy source.
Propane competes with other sources of energy, some of which are less costly for equivalent energy value. ETP competes for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources has been increasing as a result of reduced utility regulation. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a significantly less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in the United States has resulted in the availability of natural gas in many areas that previously depended upon propane. Although the extension of natural gas pipelines tends to displace propane distribution in areas affected, ETP believes that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Even though propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to another. Based upon industry publications, propane accounts for three to four percent of household energy consumption in the United States.
In addition to competing with alternative energy sources, ETP competes with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large multi-state propane marketers, thousands of smaller local independent
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marketers and farm cooperatives. Most of ETP customer service locations compete with five or more marketers or distributors. Each retail distribution outlet operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. The typical retail distribution outlet generally has an effective marketing radius of approximately 50 miles although in certain rural areas the marketing radius may be extended by satellite locations.
The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. ETP believes that its safety programs, policies and procedures are more comprehensive than many of its smaller, independent competitors and give it a competitive advantage over such retailers.
The wholesale propane business is highly competitive. For fiscal year 2004, ETP domestic wholesale operations (excluding M-P Energy Partnership) accounted for only 3.0% of its total gallons sold in the United States and approximately 1.2% of its gross profit. ETP does not emphasize wholesale operations, but it believes that limited wholesale activities enhance its ability to supply its retail operations.
Midstream, Transportation and Storage Segments
Competition
The business of providing natural gas gathering, transmission, treating, transporting, storing and marketing services is highly competitive. ETP’s principal areas of competition include retaining and obtaining, storing natural gas business, and with regard to the Southeast Texas System, obtaining significant natural gas supplies under terms favorable to ETP. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. The Southeast Texas System primarily competes with natural gas gathering and processing systems owned by Duke Energy Field Services. The ET Fuel System and the East Texas Pipeline compete with various pipelines including those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P., and Enbridge, Inc.
Many of ETP’s competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ETP’s. In marketing natural gas, ETP has numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely various sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with ETP’s marketing operations.
Credit Risk and Customers
ETP has a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users and customers in the refining and petrochemical industries. ETP is diligent in attempting to ensure that it issues credit to credit-worthy customers. However, ETP’s purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to ETP’s overall profitability.
During the year ended August 31, 2004, ETP had three customers that individually accounted for more than 10% of midstream and transportation segment revenues. While these customers represent a significant percentage of midstream and transportation segment revenues, the loss of any one of these customers would not have a material impact on ETP’s results of operations.
Regulation
Regulation by FERC of Interstate Natural Gas Pipelines. Under the Natural Gas Act (“NGA”), the Federal Energy Regulatory Commission (“FERC”) generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” service includes storage service. ETP does not own
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any interstate natural gas transportation facilities, so FERC does not directly regulate any of ETP’s pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of ETP’s business and the market for its products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:
| • | the certification and construction of new facilities; |
| • | the extension or abandonment of services and facilities; |
| • | the maintenance of accounts and records; |
| • | the acquisition and disposition of facilities; |
| • | the initiation and discontinuation of services; and |
| • | various other matters. |
Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies.
In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines’ rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Intrastate Pipeline Regulation. ETP’s intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. However, to the extent that ETP’s intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”), which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service set forth in the pipeline’s statement of operating conditions are subject to FERC review and approval. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC approved Statement of Operating Conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
ETP’s intrastate pipeline and storage operations in Texas are subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The TRRC has authority to ensure that rates charged by intrastate pipelines for natural gas sales or transportation services are just and reasonable. The rates ETP charges for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. ETP cannot predict whether such a complaint will be filed against it or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. ETP owns a number of natural gas pipelines in Texas and Louisiana that ETP believes meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of ETP’s gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.
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In Texas, ETP’s gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for its intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. ETP’s Chalkley System is regulated as an intrastate transporter, and the Office of Conservation has determined that ETP’s Whiskey Bay System is a gathering system.
ETP is subject to state ratable take and common purchaser statutes in all of the states in which it operates. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting ETP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and Federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. ETP’s gathering operations could be adversely affected should they be subject in the future to the application of state or Federal regulation of rates and services. ETP’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. ETP cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas. Sales for resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates are subject to the FERC’s regulation unless the gas is produced by the pipeline or affiliate. Under current federal rules, however, the price at which ETP sells natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. Effective as of January 12, 2004, the FERC’s rules require pipelines (including intrastate pipelines) and their affiliates who sell gas in interstate commerce subject to the FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate such code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by the FERC. The FERC denied rehearing of these rules on May 19, 2004, but the rules are still subject to possible court appeals. We cannot predict the outcome of these further proceedings, but do not believe that ETP will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, ETP’s sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed
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regulation. We cannot predict the ultimate impact of these regulatory changes to ETP’s natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.
Pipeline Safety. The states in which ETP conducts operations administer Federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the NGPSA presently exempts substantial portions of ETP’s gathering facilities from jurisdiction under that statute. The portions of ETP’s facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to ETP’s intrastate natural gas pipelines.
Products, Services and Marketing
ETP distributes propane through a nationwide retail distribution network consisting of 315 customer service locations in 34 states. ETP’s operations are concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States. ETP serves more than 700,000 active customers. Historically, approximately two-thirds of Heritage’s retail propane volumes and in excess of 90% of its EBITDA, as adjusted, (please read footnote (e) under “Selected Historical Financial Data”—and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a more detailed discussion of EBITDA, as adjusted) were attributable to sales during the six-month peak heating season from October through March, as many customers use propane for heating purposes. Consequently, sales and operating profits are normally concentrated in the first and second fiscal quarters, while cash flows from operations are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak season. To the extent necessary, ETP will reserve cash from peak periods for distribution to its unitholders during the warmer seasons.
Typically, customer service locations are found in suburban and rural areas where natural gas is not readily available. Generally, such locations consist of a one to two acre parcel of land, an office, a small warehouse and service facility, a dispenser and one or more 18,000 to 30,000 gallon storage tanks. Propane is generally transported from refineries, pipeline terminals, leased storage facilities and coastal terminals by rail or truck transports to ETP’s customer service locations where it is unloaded into storage tanks. In order to make a retail delivery of propane to a customer, a bobtail truck is loaded with propane from the storage tank. Propane is then delivered to the customer by the bobtail truck, which generally holds 2,500 to 3,000 gallons of propane, and pumped into a stationary storage tank on the customer’s premises. ETP also delivers propane to retail customers in portable cylinders. ETP also delivers propane to certain other bulk end-users of propane in tractor-trailer transports, which typically have an average capacity of approximately 10,500 gallons. End-users receiving transport deliveries include industrial customers, large-scale heating accounts, mining operations and large agricultural accounts.
ETP encourages its customers whose propane needs are temperature sensitive to implement a regular delivery schedule. Many of ETP’s residential customers receive their propane supply pursuant to an automatic delivery system, which eliminates the customer’s need to make an affirmative purchase decision and allows for more efficient route scheduling. ETP also sells, installs and services equipment related to its propane distribution business, including heating and cooking appliances.
ETP owns, through its subsidiaries, a 60% interest in M-P Energy Partnership, a Canadian partnership that supplies ETP with propane as described below under “Propane Supply and Storage.”
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Approximately 97% of the domestic gallons that ETP sold in the fiscal year ended August 31, 2004 were to retail customers and 3% were to wholesale customers. Of the retail gallons ETP sold, approximately 57% were to residential customers, 27% were to industrial, commercial and agricultural customers, and 16% were to other retail users. Sales to residential customers in the fiscal year ended August 31, 2004 accounted for 55% of total domestic gallons sold but accounted for approximately 70% of ETP’s gross profit from propane sales. Residential sales have a greater profit margin and a more stable customer base than the other markets ETP serves. Industrial, commercial and agricultural sales accounted for 21% of ETP’s gross profit from propane sales for the fiscal year ended August 31, 2004, with all other retail users accounting for 9%. Additional volumes sold to wholesale customers contributed 1% of ETP’s gross profit from propane sales. No single customer accounts for 10% or more of revenues. These figures are on a aggregate basis, which includes the historical figures of the operations of HOLP from the period from September 1, 2003 through August 31, 2004.
The propane business is very seasonal with weather conditions significantly affecting demand for propane. ETP believes that the geographic diversity of its operations helps to reduce its overall exposure to less than favorable weather conditions in any particular region of the United States. Although overall demand for propane is affected by climate, changes in price and other factors, we believe its residential and commercial business to be relatively stable due to the following characteristics:
| • | residential and commercial demand for propane has been relatively unaffected by general economic conditions due to the largely non-discretionary nature of most propane purchases, |
| • | loss of customers to competing energy sources has been low due to the lack of availability or the high cost of alternative fuels; |
| • | the tendency of customers to remain with ETP due to the product being delivered pursuant to a regular delivery schedule and to its ownership as of August 31, 2004 of 90% of the storage tanks utilized by its customers, which prevents fuel deliveries from competitors; and |
| • | its historic ability to more than offset customer losses through internal growth of its customer base in existing markets. |
Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which ETP operates can significantly affect the total volumes of propane that ETP sells and the margins realized thereon and, consequently, ETP’s results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.
Propane Supply and Storage
Supplies of propane from ETP’s sources have historically been readily available. ETP purchases from over 50 energy companies and natural gas processors at numerous supply points located in the United States and Canada. In the fiscal year ended August 31, 2004, Enterprise Products Operating L.P. (“Enterprise”) and Dynegy Liquids Marketing and Trade (“Dynegy”) provided approximately 24.9% and 18.8% of ETP’s and Heritage’s combined total propane supply, respectively. In addition, M-P Energy Partnership, a Canadian partnership in which its wholly owned subsidiary M.P. Oils, Ltd. owns a 60% interest in, procured 19% of Heritage’s combined total propane supply during the fiscal year ended August 31, 2004. M-P Energy Partnership buys and sells propane for its own account and supplies propane to us for ETP’s northern United States operations.
ETP believes that if supplies from Enterprise and Dynegy were interrupted it would be able to secure adequate propane supplies from other sources without a material disruption of its operations. Aside from Enterprise, Dynegy and the supply procured by M-P Energy Partnership, no single supplier provided more than 10% of ETP’s total domestic propane supply during the fiscal year ended August 31, 2004. ETP believes that its diversification of suppliers will enable it to purchase all of its supply needs at market prices without a material
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disruption of its operations if supplies are interrupted from any of ETP’s existing sources. Although we cannot assure you that supplies of propane will be readily available in the future, we expect a sufficient supply to continue to be available. However, increased demand for propane in periods of severe cold weather, or otherwise, could cause future propane supply interruptions or significant volatility in the price of propane.
ETP typically enters into one-year supply agreements. The percentage of contract purchases may vary from year to year. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major delivery or storage points, and some contracts include a pricing formula that typically is based on these market prices. Most of these agreements provide maximum and minimum seasonal purchase guidelines. ETP receives its supply of propane predominately through railroad tank cars and common carrier transport.
Because ETP’s profitability is sensitive to changes in wholesale propane costs, ETP generally seeks to pass on increases in the cost of propane to customers. ETP has generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane, but there is no assurance that ETP will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, ETP’s profitability will be sensitive to changes in wholesale propane prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”
ETP leases space in larger storage facilities in New York, Georgia, Michigan, South Carolina, Arizona, New Mexico, Texas, Alberta, Canada and smaller storage facilities in other locations and has the opportunity to use storage facilities in additional locations when ETP’s “pre-buy” product from sources having such facilities. ETP believes that it has adequate third party storage to take advantage of supply purchasing advantages as they may occur from time to time. Access to storage facilities allows ETP to buy and store large quantities of propane during periods of low demand, which generally occur during the summer months, or at favorable prices, thereby helping to ensure a more secure supply of propane during periods of intense demand or price instability.
Pricing Policy
Pricing policy is an essential element in the marketing of propane. ETP relies on its regional management to set prices based on prevailing market conditions and product cost, as well as local management input. All regional managers are advised regularly of any changes in the posted price of each customer service location’s propane suppliers. In most situations, ETP believes that its pricing methods will permit it to respond to changes in supply costs in a manner that protects its gross margins and customer base, to the extent such protection is possible. In some cases, however, ETP’s ability to respond quickly to cost increases could occasionally cause its retail prices to rise more rapidly than those of its competitors, possibly resulting in a loss of customers.
Billing and Collection Procedures
Customer billing and account collection responsibilities for ETP’s propane operations are retained at the local customer service locations. ETP believes that this decentralized approach is beneficial for several reasons:
| • | the customer is billed on a timely basis; |
| • | the customer is more apt to pay a “local” business; |
| • | cash payments are received more quickly; and |
| • | local personnel have a current account status available to them at all times to answer customer inquiries. |
Because propane sales to residential and commercial customers are affected by winter heating season requirements, ETP’s propane operations generally generate higher operating revenues and net income during the period from October through March of each year and lower operating revenues and, in some cases, net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather-sensitive.
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Gross profit margins are not only affected by weather patterns but also by changes in customer mix. For example, sales to residential customers generate higher margins than sales to other customer groups, such as commercial or agricultural customers. Wholesale margins are substantially lower than retail margins. In addition, gross profit margins vary by geographic region. Accordingly, a change in customer or geographic mix can affect gross profit without necessarily affecting total revenues.
Government Regulation and Environmental Matters
The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair ETP’s business activities that affect the environment in many ways, such as:
| • | restricting the way it can release materials including petroleum hydrocarbons and wastes into the air, water, or soils; |
| • | limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted; |
| • | requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and |
| • | imposing substantial liabilities on ETP for pollution resulting from its operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms. |
Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. ETP has implemented environmental programs and policies designed to avoid potential liability and cost under applicable environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, risks of process upsets, accidental releases or spills are associated with ETP’s operations, and we cannot assure you that ETP will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, ETP may be unable to pass on those increases to its customers. While we believe that ETP is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on ETP, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment, including those arising out of historical operations conducted by predecessors. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although “petroleum” is excluded from the definition of hazardous
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substance under CERCLA, ETP will generate materials in the course of its operations that may be regulated as hazardous substances. ETP also may incur liability under the Resource Conservation and Recovery Act, also known as “RCRA,” which imposes requirements related to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of its operations, ETP may generate unrecovered petroleum product wastes as well as ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous or solid wastes.
ETP currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although ETP used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by ETP, or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under its control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, ETP could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. A predecessor company acquired by ETP in July 2001 had previously received and responded to a request for information from the U.S. Environmental Protection Agency or “EPA” regarding its potential contribution to widespread groundwater contamination in San Bernardino, California, known as the Newmark Groundwater Contamination Superfund site. ETP has not received any follow-up correspondence from EPA on the matter since ETP’s acquisition of the predecessor company in 2001. In addition, ETP is currently involved in several remediation projects, that have cleanup costs and related liabilities collectively estimated at between $1.3 million and $2.0 million, with the most significant of these remedial projects estimated to be between $1.1 million and $1.8 million. However, with respect to this latter remedial project, ETP expects to recover approximately $0.5 million to $0.8 million of the estimated cleanup costs and liabilities pursuant to a contractual requirement that makes a predecessor owner responsible for one-half of these environmental costs and liabilities. As of June 1, 2005, ETP has established environmental accruals totaling approximately $0.42 million for cleanup and remediation of properties.
The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from ETP’s systems or facilities could result in fines or penalties, as well as significant remedial obligations. We believe that ETP is in substantial compliance with the Clean Water Act. ETP currently expects to incur costs of approximately $0.1 million over the next year to upgrade or modify certain facilities as required under its spill prevention, control and countermeasures, or “SPCC,” plans.
The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require ETP to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Failure to comply with these laws and regulations could expose ETP to civil and criminal enforcement actions.
ETP’s operations are subject to regulation by the U.S. Department of Transportation or “DOT” under the Hazardous Liquid Pipeline Safety Act, or “HLPSA,” pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA requires any entity which owns or operates pipeline facilities to permit access to and allow copying of records and to make certain reports and provide information as required by DOT. While we believe
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that ETP’s pipeline operations are in substantial compliance with applicable HLPSA requirements, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on ETP’s operations or financial position. Moreover, the DOT, through the Office of Pipeline Safety, has promulgated rules requiring pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact “high consequence areas,” including areas with specified population densities. Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing, or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. ETP estimates that the costs of implementing these integrity management plans is $10 million per year, over the years 2006 to 2011.
ETP is subject to the requirements of the federal Occupational Safety and Health Act, also known as OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in ETP’s operations and that this information be provided to employees, state and local government authorities and citizens. We believe that ETP’s operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which ETP operates. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. With respect to the transportation of propane by truck, ETP is subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT. ETP conducts ongoing training programs to help ensure that its operations are in compliance with applicable regulations. We believe that the ETP procedures currently in effect at all of its facilities for the handling, storage, and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.
To carry out its operations for the midstream and transportation segments, ETP employs 525 people as of May 31, 2005. As of May 31, 2005, its propane operations had 2,589 full time employees. Of ETP’s operational employees, 50 are represented by labor unions. ETP believes that its relations with its employees are satisfactory. Historically, Heritage has also hired seasonal workers to meet peak winter demands in its propane operations.
Substantially all of ETP’s pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. ETP has obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which ETP’s pipelines were built was purchased in fee.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to ETP will require the consent of the current landowners to transfer these rights, which in some instances are governmental entities. ETP believes that it has obtained or will obtain sufficient third party consents, permits and authorizations for the transfer of the assets necessary for it to operate its business in all material respects as described in this prospectus. With respect to any consents, permits or authorizations that have not been obtained, ETP believes that these consents, permits or authorizations will be obtained, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of ETP’s business.
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ETP owns two office buildings with a total of 15,988 square feet of space for its executive offices in Dallas, Texas. ETP also leases office facilities in Houston, Texas, San Antonio, Texas, Tulsa, Oklahoma, and Helena, Montana, which consist of 49,000 square feet, 39,235 square feet, 6,740 square feet, and 22,000 square feet, respectively. While ETP may require additional office space as its business expands, ETP believes that its existing facilities are adequate to meet its needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed. ETP is currently constructing new office facilities to replace its leased facility in Helena, Montana, which is for the administration of its propane operations.
ETP operates bulk storage facilities at over 300 customer service locations for its propane operations. ETP owns substantially all of these facilities and has entered into long-term leases for those that it does not own. ETP believes that the increasing difficulty associated with obtaining permits for new propane distribution locations makes its high level of site ownership and control a competitive advantage. ETP owns approximately 21.5 million gallons of above ground storage capacity at its various propane plant sites and has leased an aggregate of approximately 46 million gallons of underground storage facilities in New York, Georgia, Michigan, South Carolina, Arizona, New Mexico, Texas and Alberta, Canada. ETP does not own or operate any underground propane storage facilities (excluding customer and local distribution tanks) or propane pipeline transportation assets (other than local delivery systems).
Prior to January 2004, Heritage owned a 50% interest in Bi-State Propane, a California general partnership that conducts business in California and Nevada. In January 2004, Heritage’s subsidiary, Heritage Bi-State, L.L.C., acquired 100% of the assets of Bi-State Propane, and ETP conducts those operations under the tradename Bi-State Propane.
The transportation of propane requires specialized equipment. The trucks and railroad tank cars used for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of August 31, 2004, ETP utilized approximately 52 transport truck tractors, 50 transport trailers, 10 railroad tank cars, 1,157 bobtails and 1,804 other delivery and service vehicles, all of which ETP own. As of August 31, 2004, ETP owned approximately 690,000 customer storage tanks with typical capacities of 120 to 1,000 gallons that are leased or available for lease to customers. These customer storage tanks are pledged as collateral to secure ETP’s obligations to its banks and the holders of its notes.
ETP utilizes a variety of trademarks and tradenames in its propane operations that it owns or has secured the right to use, including “Heritage Propane.” These trademarks and tradenames have been registered or are pending registration before the United States Patent and Trademark Office or the various jurisdictions in which the marks or tradenames are used. ETP believes that its strategy of retaining the names of the companies it has acquired has maintained the local identification of these companies and has been important to the continued success of these businesses. Some of ETP’s most significant trade names include Balgas, Bi-State Propane, Blue Flame Gas of Charleston, Blue Flame Gas of Mt. Pleasant, Blue Flame Gas, Carolane Propane Gas, Gas Service Company, EnergyNorth Propane, Gibson Propane, Guilford Gas, Holton’s L.P. Gas, Ikard & Newsom, Northern Energy, Sawyer Gas, ProFlame, Rural Bottled Gas and Appliance, ServiGas, and V-1 Propane. ETP regards its trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of its products.
ETP believes that it has satisfactory title to or valid rights to use all of its material properties. Although some of such properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, ETP does not believe that any such burdens will materially interfere with its continued use of such properties in its business, taken as a whole. In addition, ETP believes that it has, or is in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and has obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of ETP’s properties or the operations of its business.
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Although ETP’s midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of its business, ETC OLP is not currently a party to any material legal proceedings. In addition, ETP is not aware of any material legal or governmental proceedings against ETC OLP, or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.
Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, ETP is sometimes threatened with or is named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. ETP maintains liability insurance with insurers in amounts and with coverages and deductibles it believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect ETP from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, ETP does not believe that pending or threatened litigation matters will have a material adverse effect on ETP’s financial condition or results of operations.
Of the pending or threatened matters in which ETP is a party, none have arisen outside the ordinary course of its business except for an action filed by Heritage on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. in the Fifth Judicial Circuit Court of Common Pleas, Richland county, South Carolina (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P. and they were dismissed from the litigation. The trial began on October 4, 2004 against the remaining defendants and testimony was concluded on October 20, 2004. On October 21, 2004, the jury returned a verdict in favor of Heritage against SCANA and in favor of defendant Suburban. The jury found in favor of Heritage on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. SCANA has appealed the jury’s decision, and currently, the parties are involved in the appeal of a number of post-trial motions. We cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. As a result, we cannot yet predict whether ETP will receive any of the damages award covered by this verdict.
ETP issued 1,000,000 class C units to Heritage Holdings in August 2000 in conjunction with the transaction with Energy Transfer Partners, L.L.C. and the change of control of ETP’s general partner in conversion of that portion of Heritage Holding’s incentive distribution rights that entitled it to receive any distribution attributable to the net amount received by ETP in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation.
As soon as practicable after the time that ETP or its affiliates receive any final cash or other payment as a result of the resolution of the SCANA litigation, the special litigation committee will determine the aggregate net amount of these proceeds distributable by ETP after deducting from the amounts received all costs and expenses incurred by ETP and its affiliates in connection with the SCANA litigation and any cash reserves necessary or appropriate to provide for operating expenditures. The amount of distributable proceeds that would normally be distributed to holders of incentive distribution rights will instead be distributed to the holders of the class C units, pro rata. ETP cannot predict whether it will receive any cash payments as a result of the SCANA litigation and, if so, when these distributions might be made to the class C unitholders.
At the time of the Houston Pipeline System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”) and the parent companies of the HPL Entities were engaged in ongoing litigation with Bank of America that related to AEP’s acquisition of the Houston Pipeline in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage
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facility (Cushion Gas). We refer to this litigation as the “Cushion Gas Litigation”. Under the terms of the purchase and sale agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the purchase and sale agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
ETP is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of ETP. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, ETP accrues the related deductible. As of August 31, 2004 and 2003, an accrual of $930 and $112, respectively, was recorded as accrued and other current liabilities on ETP’s consolidated balance sheets.
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Directors and Officers of LE GP, LLC
The following table sets forth certain information with respect to our executive officers, including key executive officers of ETP, our significant subsidiary, and members of the board of directors of our general partner, LE GP, LLC. Executive officers and directors will serve until their successors are duly appointed or elected.
| Name |
Age |
Position | ||
| John W. McReynolds |
54 | President, Chief Financial Officer of our General Partner | ||
| Ray C. Davis |
63 | Co-Chief Executive Officer and Co- Chairman of the Board of Directors of ETP | ||
| Kelcy L. Warren |
49 | Co-Chief Executive Officer and Co- Chairman of the Board of Directors of ETP | ||
| Kenneth A. Hersh |
42 | Director of our General Partner | ||
| David R. Albin |
46 | Director of our General Partner | ||
| Daniel Rioux |
37 | Director of our General Partner | ||
| K. Rick Turner |
47 | Director of our General Partner |
| (1) | Upon the closing of the offering, this director will resign from the board of directors of our general partner. |
John W. McReynolds. Mr. McReynolds has served as our the President since March 2005 and served as our Chief Financial Officer since August 2005. Effective upon closing of this offering, Mr. McReynolds will be appointed as a director of Energy Transfer Equity. He is also a director of Energy Transfer Partners. Prior to becoming President of Energy Transfer Equity, Mr. McReynolds was a partner with the international law firm of Hunton & Williams LLP, for over 20 years. As a lawyer, he specialized in energy-related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation and governmental proceedings, including as an expert in special projects for boards of directors of public companies.
Ray C. Davis. Mr. Davis is Co-Chief Executive Officer and Co-Chairman of the Board of Directors of the general partner of ETP and has served in that capacity since the combination of the midstream and transportation operations of LaGrange Acquisition and the retail propane operations of Heritage in January 2004. Mr. Davis also serves as Co-Chief Executive Officer of the general partner of ETC OLP, and as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Davis served as Vice President of the general partner of ET Company I, Ltd., the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the board of directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more than 31 years of business experience in the energy industry.
Kelcy L. Warren. Mr. Warren is the Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETP and has served in that capacity since the combination of the midstream and transportation operations of LaGrange Acquisition and the retail propane operations of Heritage in January 2004. Mr. Warren also serves as Co-Chief Executive Officer of the general partner of ETC OLP, and as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd., having served in that capacity since 1996. From 1996 to 2000, he served as a director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.
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David R. Albin. Mr. Albin is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1988. Prior to his participation as a founding member of Natural Gas Partners, L.P. in 1988, he was a partner in the $600 million Bass Investment Limited Partnership. Prior to joining Bass Investment Limited Partnership, he was a member of the oil and gas group in the investment banking division of Goldman, Sachs & Co. Mr. Albin has served as a director of Energy Transfer Partners GP since February 2004 and has served as a director of our general partner since October 2002.
Kenneth A. Hersh. Mr. Hersh is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. Mr. Hersh has served as a director of Energy Transfer Partners GP since February 2004 and has served as a director of our general partner since October 2002.
Daniel Rioux. Mr. Rioux is the Vice President and Treasurer of Liberty Energy Holdings, LLC, which invests in oil and gas exploration and production, as well as related private equity transactions, on behalf of its insurance company parent. Prior to joining Liberty Energy Holdings, LLC, Mr. Rioux was Vice President of Liberty Energy Corporation, now a subsidiary of Liberty Energy Holdings, LLC, which invests in oil and gas exploration and production, as well as related private equity transactions, on behalf of its insurance company parent. He currently serves as a director of Petrohawk Energy Corporation. Mr. Rioux has served as a director of our general partner since October 2002.
K. Rick Turner. Mr. Turner has been a principal of Stephens, Inc., one of the largest off-Wall Street investment banking groups, since 1990. Mr. Turner’s areas of focus include oil and gas exploration, natural gas gathering and processing industries, and power technology. He currently serves as a director of Atlantic Oil Corporation; SmartSignal Corporation; Jebco Seismic, LLC; North American Energy Partners Inc.; and JV Industrial Companies, Ltd. Mr. Turner has served as a director of Energy Transfer Partners GP since February 2004 and is chairman of the compensation committee and has served as a director of our general partner since October 2002.
The board of directors of our general partner has the authority to appoint our executive officers and directors, subject to provisions in the limited liability company agreement of the general partner of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of Mr. McReynolds as our chief executive officer, to appoint a replacement chief executive officer.
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Board Committees
Audit and Conflicts Committee. Our general partner’s board of directors has established an audit and conflicts committee to be effective upon the closing of this offering. Ultimately, three members of our general partner’s board of directors will serve on the audit and conflicts committee, which will review our external financial reporting, maintain responsibility for engaging our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. In addition, this committee will be charged with reviewing specific matters that our general partner’s board of directors believes may involve conflicts of interest. The audit and conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the audit and conflicts committee must meet the independence standards for an audit and conflicts committee of a board of directors, which standards are established by the NYSE. Any matters approved by the audit and conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our unitholders, and not a breach by us of any duties we may owe to our unitholders. Upon completion of this offering, we will have an audit committee that complies with the independence standards of the NYSE.
Compensation Committee. Our general partner’s board of directors has established a compensation committee of at least two independent directors to be effective upon the closing of this offering. The compensation committee will oversee compensation decisions and benefits for the officers of our general partner.
Other Committees. Our general partner’s board of directors may establish other committees from time to time to facilitate our management.
Governance Matters
Independence of Board Members. Our general partner is committed to having a board of directors that consists of at least two independent directors. Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with our general partner or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with our general partner or us). In compliance with the corporate governance rules of the NYSE, the members of the board of directors of our general partner will appoint one independent member prior to the closing of this offering and a second independent member within three months of listing. The independent members of the board of directors of our general partner will serve as the initial members of the audit and conflicts and governance committees.
Heightened Independence for Audit Committee Members. As required by the Sarbanes-Oxley Act of 2002, the Commission has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. The board of directors of our general partner expects that all members of its audit and conflicts committee will satisfy this heightened independence requirement.
Audit Committee Financial Expert. An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the Sarbanes-Oxley Act of 2002, Commission rules require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses all of the following attributes:
| • | An understanding of generally accepted accounting principles and financial statements; |
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| • | An ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves; |
| • | Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by our financial statements, or experience actively supervising one or more persons engaged in such activities; |
| • | An understanding of internal controls and procedures for financial reporting; and |
| • | An understanding of audit committee functions. |
The board of directors of our general partner expects that one of the independent directors will satisfy the definition of “audit committee financial expert.”
Executive Sessions of Board. The board of directors of our general partner will hold regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the “presiding director,” who is responsible for leading and facilitating such executive sessions.
Election of our Directors
Our general partner’s limited liability company agreement establishes a board of directors that will be responsible for the oversight of our business and operations. Our general partner’s board of directors will be elected by the members of our general partner.
Executive and Incentive Compensation
John W. McReynolds, the President of Energy Transfer Equity, is entitled to receive a base salary of $350,000 per year and an initial annual bonus and future bonuses to be determined by the compensation committee of the board of directors of our general partner. He is also entitled to participate in any incentive plan under which we award short-term or long-term incentive awards or other compensatory awards.
We have adopted the Energy Transfer Equity Class B Unit Incentive Plan for the employees and directors of our general partner. This plan is intended to provide long-term incentives for our employees and directors based on the appreciation in the equity value of our common units. This plan provides for an initial grant of Class B units to Mr. McReynolds, a potential additional grant of Class B units to Mr. McReynolds upon the closing of this offering and, subject to the performance criteria related to appreciation in our equity market capitalization as described below, an annual grant of Class B units to Mr. McReynolds and other persons eligible to participate in the plan on January 2 of each year thereafter following the completion of this offering. The compensation committee of the board of directors of our general partner will be entitled to determine any awards of the Class B units that may be granted each year among the persons entitled to participate in the plan.
In general, the number of Class B units granted under this plan upon any particular grant date will be based upon the amount, if positive, by which our adjusted enterprise value, exceeds the value of Class B units previously issued under the plan. Our adjusted enterprise value on the date of a grant is an amount equal to 5% of our equity market capitalization as of the date of the grant, as determined without regard to the ETP common units we own on the date of the grant, which is in excess of $400.0 million. Each Class B unit will represent a limited partner interest in us and will be entitled to receive quarterly cash distributions in the same amount as the quarterly cash distributions we make on each common unit. Each Class B unit will be allocated a portion of our income, gain, loss, deduction and credit in a pro rata basis with each common unit, and each Class B unit will be entitled to receive distributions upon liquidation in the same manner as each common unit. Each Class B unit will also have the same voting rights as a common unit. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit. The Class B units will not be subject to vesting.
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A similar plan has been adopted by Energy Transfer Investments, L.P., the entity that owns an equity interest in Energy Transfer Partners GP which entitles it to receive 50% of the cash distributions relating to the incentive distribution rights of ETP. Mr. McReynolds will be entitled to receive an equal number of Class B units of Energy Transfer Investments as the number of Class B units he receives under our plan. We do not own any interest or realize any benefit from Energy Transfer Investments, L.P.
Energy Transfer Equity Long-Term Incentive Plan
We will adopt the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our general partner and employees, directors and consultants of our affiliates who perform services for us. The long-term incentive plan will consist of all or any of the following four components: restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by the compensation committee of the board of directors of our general partner.
The board of directors of our general partner and the compensation committee of the board may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our board of directors and the compensation committee of the board also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as may be required by the exchange upon which the common units are listed at that time, if any. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will expire upon its termination by the board of directors or the compensation committee or, if earlier, when no units remain available under the plan for awards. Awards then outstanding will continue pursuant to the terms of their grants.
Restricted Units. A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. In the future, the compensation committee may determine to make grants of restricted units under the plan to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control, as defined in the plan. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted unit. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.
Common units to be delivered as restricted units may be common units acquired by us in the open market, common units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon the grant of the restricted units, the total number of common units outstanding will increase.
We intend the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. In the future, the compensation committee may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which phantom units granted to employees and members of our board will vest. The committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the phantom units will vest upon a change in control. If
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a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.
Common units to be delivered upon the vesting of phantom units may be common units acquired by us in the open market, common units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon vesting of the phantom units, the total number of common units outstanding will increase.
We intend the issuance of any common units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
Unit Options. The long-term incentive plan will permit the grant of options covering common units. The compensation committee may make grants under the plan to employees, consultants and members of our board containing such terms as the committee determines. Unit options will have an exercise price that may be greater or less than the fair market value of the units on the date of grant, in the discretion of the compensation committee. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise.
Upon exercise of a unit option, we will issue new common units, acquire common units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee’s discretion. If we issue new common units upon exercise of the unit options (or a unit appreciation right settled in common units), the total number of common units outstanding will increase. The availability of unit options is intended to furnish additional compensation to employees, consultants and members of our board of directors and to align their economic interests with those of common unitholders.
Unit Appreciation Rights. The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in common units or, in the discretion of the compensation committee, in cash. Initially, we do not expect to grant unit appreciation rights under our long-term incentive plan. In the future, the compensation committee may determine to make grants of unit appreciation rights under the plan to employees and members of our board of directors containing such terms as the committee determines. Unit appreciation rights will have an exercise price that may be greater or less than the fair market value of the common units on the date of grant, in the discretion of the compensation committee. In general, unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit appreciation rights will become exercisable upon a change in control. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or compensation committee provides otherwise.
Upon exercise of a unit appreciation right settled in common units, we will issue new common units, acquire common units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee’s discretion. If we issue new common units upon exercise of the unit appreciation right settled in common units, the total number of common units outstanding will increase. The availability of unit appreciation rights is intended to furnish additional compensation to employees, consultants and members of our board of directors and to align their economic interests with those of common unitholders.
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Distribution Equivalent Rights. The compensation committee may, in its discretion, grant distribution equivalent rights (“DERs”) with respect to awards other than restricted units. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the Award is outstanding. Payment of a DER may be subject to the same vesting terms as the award to which it relates.
U.S. Federal Income Tax Consequences of Awards Under the Long-Term Incentive Plan. When an option or unit appreciation right is granted, there are no income tax consequences for the participant or us. When an option or unit appreciation right is exercised, the participant recognizes compensation equal to the excess of the fair market value of the common unit on the date of exercise over the exercise price multiplied by the number of common units subject to the option or unit appreciation right that was exercised. In general, we are entitled to a deduction equal to the compensation recognized by the participant for our taxable year that ends with or within the taxable year in which the participant recognized the compensation. Special tax rules may apply to options and unit appreciation rights that are granted with an exercise price below the fair market value of a unit on the date of grant, which may subject the participant to an additional 20% tax on the compensation recognized with respect to such award. It is unclear under current IRS guidance whether these special rules will also apply to all options and unit appreciation rights.
Generally, when phantom units, DERs or restricted units are granted, there are no income tax consequences for the participant or us. Upon the payment to the participant of common units and/or cash in respect of the award or the release of restrictions on restricted units, including any distributions that have been made thereon, the participant recognizes compensation equal to the fair market value of the cash and/or units as of the date of delivery or release.
Compensation of Directors
Historically, our general partner has paid no compensation to members of its board of directors for their service as directors. No additional remuneration will be paid to officers or employees of our general partner who also serve as directors. We anticipate that each independent director will receive a combination of cash, common unit options and restricted common unit grants as compensation for services rendered, including attending annual meetings of the board of directors and committee meetings. In addition, each independent director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law. Further, our general partner has entered into indemnity agreements with each of its directors.
Compensation Committee Interlocks and Insider Participation
None of our executive officers has served as a member of the compensation committee of any entity that has one or more of its executive officers serving as a member of the board of directors or compensation committee of our general partner. John McReynolds, ETE’s president and chief financial officer, currently serves as a director of ETP.
Each of our board committees will adopt a formal written charter prior to the closing of this offering.
Governance Guidelines. Governance guidelines, together with committee charters, provide the framework for effective governance. The board of directors of our general partner will adopt governance guidelines addressing several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of committees, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The board of directors of our general partner recognizes that effective governance is an on-going process, and thus, the board will review the Energy Transfer Equity’s governance guidelines annually or more often as deemed necessary.
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Code of Ethics. The board of directors of our general partner will adopt a code of ethics, the “Code of Ethical Conduct for Senior Financial Officers and Managers,” that applies to the chief executive officer, chief financial officer, principal accounting officer and senior financial and other managers or anyone acting in those capacities under the shared services agreement. In addition to other matters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code.
Web Access. We will provide access through our website at www.energytransfer.com/ete to current information relating to governance, including a copy of each board committee charter, the Code of Ethical Conduct for Senior Financial Officers and Managers, the Energy Transfer Equity governance guidelines and other matters impacting our governance principles. You may also contact our investor relations department for paper copies of these documents free of charge.
Directors and Executive Officers of Energy Transfer Partners
The following table sets forth certain information with respect to the executive officers and members of the board of directors of Energy Transfer Partners as of August 31, 2005. Executive officers and directors are elected for one-year terms.
| Name |
Age |
Position | ||
| Ray C. Davis |
63 | Co-Chief Executive Officer and Co-Chairman of the Board of Directors | ||
| Kelcy L. Warren |
49 | Co-Chief Executive Officer and Co-Chairman of the Board of Directors | ||
| H. Michael Krimbill |
52 | President, Chief Financial Officer and Director | ||
| R.C. Mills |
67 | Executive Vice President and Chief Operating Officer | ||
| Mackie McCrea |
46 | Senior Vice President—Commercial Development | ||
| Bradley K. Atkinson |
50 | Vice President—Corporate Development | ||
| Robert A. Burk |
48 | Vice President and General Counsel and Secretary | ||
| John W. Daigh (1) |
49 | Vice President and Treasurer | ||
| Karen Z. Hicks (2) |
42 | Vice President of Administration and Controller | ||
| Stephen L. Cropper |
55 | Director of the General Partner | ||
| Bill W. Byrne |
75 | Director of the General Partner | ||
| J. Charles Sawyer |
69 | Director of the General Partner | ||
| David R. Albin |
46 | Director of the General Partner | ||
| Kenneth A. Hersh |
42 | Director of the General Partner | ||
| Paul E. Glaske |
72 | Director of the General Partner | ||
| K. Rick Turner |
47 | Director of the General Partner | ||
| Ted Collins, Jr. |
67 | Director of the General Partner | ||
| John W. McReynolds |
54 | Director of the General Partner |
| (1) | Elected Vice President and Treasurer in September 2004. |
| (2) | Elected Vice President of Administration in September 2004. |
As described above, some of the directors of our general partner, LE GP, LLC, also serve as directors of the general partner of Energy Transfer Partners.
Ray C. Davis. Mr. Davis is Co-Chief Executive Officer and Co-Chairman of the Board of Directors of the general partner of ETP and has served in that capacity since the combination of the midstream and transportation
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operators of La Grange Acquisition and the retail propane operators of Heritage in January 2004. Mr. Davis also serves as Co-Chief Executive Officer of the general partner of ETC OLP, and as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Davis served as Vice President of the general partner of ET Company I, Ltd., the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the board of directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more than 31 years of business experience in the energy industry.
Kelcy L. Warren. Mr. Warren is the Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETP and has served in that capacity since the combination of the midstream and transportation operations of La Grange Acquisition and the retail propane operators of Heritage in January 2004. Mr. Warren also serves as Co-Chief Executive Officer of the general partner of ETC OLP, and as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd., having served in that capacity since 1996. From 1996 to 2000, he served as a director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.
H. Michael Krimbill. Mr. Krimbill is the President, the Chief Financial Officer of Energy Transfer Partners GP, the general partner of ETP. Mr. Krimbill joined Heritage as Vice President and Chief Financial Officer in 1990. He served as President of Heritage from April 1999 to January 2004 and as President and Chief Executive Officer of Heritage from March 2000 to January 2004. Mr. Krimbill has served as a director of Energy Transfer Partners GP since his election in August 2000.
R.C. Mills. Mr. Mills is the Executive Vice President and Chief Operating Officer of Energy Transfer Partners GP. Mr. Mills is also the President of HOLP. Mr. Mills has over 40 years of experience in the propane industry. Mr. Mills joined Heritage in 1991 as Executive Vice President and Chief Operating Officer. Before coming to Heritage, Mr. Mills spent 25 years with Texgas Corporation in various capacities, including as the Executive Vice President and Chief Operating Officer.
Mackie McCrea. Mr. McCrea is the Senior Vice President—Commercial Development of Energy Transfer Partners GP and has served in that capacity since the combination of the operations of Energy Transfer and Heritage in January 2004. Prior to the combination of the operations of La Grange Acquisition and Heritage, Mr. McCrea served as Senior Vice President—Business Development and Producer Services of the general partner of ETC OLP and ET Company I, Ltd., having served in that capacity since 1997.
Bradley K. Atkinson. Mr. Atkinson is Vice President—Corporate Development of Energy Transfer Partners GP and has served in that capacity since August 2000. Mr. Atkinson joined Heritage on April 16, 1998 as Vice President of Administration. Prior to joining Heritage, Mr. Atkinson spent 12 years with MAPCO/ Thermogas, eight of which were spent in the acquisitions and business development group of Thermogas.
Robert A. Burk. Mr. Burk is Vice President—General Counsel and Secretary of Energy Transfer Partners GP and has served in that capacity since February 2004. Prior to joining ETP, Mr. Burk was a partner in the law firm of Doerner, Sanders, Daniel & Anderson, LLP, which served as outside counsel to Heritage since shortly after its formation and prior to its initial public offering in 1996.
John W. Daigh. Mr. Daigh is Vice President and Treasurer of Energy Transfer Partners GP and has served in that capacity since September 2004. Mr. Daigh joined ETP in October 2002, serving as ETC OLP’s Vice President and Controller until assuming his current role as Vice President and Treasurer. Mr. Daigh served as
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Vice President of Economics at Aquila, Inc. from 1999 until the time that ETP acquired its assets in 2002. Mr. Daigh also served in various controller and management roles at Koch Industries, Inc. prior to joining Aquila, Inc. in 1999.
Karen Z. Hicks. Ms. Hicks is Vice President of Administration and Controller of Energy Transfer Partners GP serving in that capacity since September 2004 and has served as Controller of Energy Transfer Partners GP since July 2002. Ms. Hicks has spent 16 years in the propane industry, all of which have been with ETP and Heritage. Ms. Hicks started her career with Heritage as Accounting Manager and was promoted to Manager of Financial Reporting when Heritage went public in 1996. In December 2000, Ms. Hicks was promoted to Assistant Controller and was promoted to Partnership Controller July 2002. Prior to her career in the propane industry, Ms. Hicks was a bank examiner for the State of Montana for three years.
Stephen L. Cropper. Mr. Cropper spent 25 years with The Williams Companies before retiring in 1998, as President and Chief Executive Officer of Williams Energy Services. Mr. Cropper is a director of NRG Energy, Inc. where he serves as the chairman of the corporate governance and nominating committee. Mr. Cropper also serves as a director, Chairman of the audit committee, and member of the Compensation Committee of Sun Logistics Partners L.P. Mr. Cropper is a director and serves as the Chairman and an Audit Committee financial expert of Berry Petroleum Company. Mr. Cropper is a director of Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group. Mr. Cropper is also a director and serves as the Chairman of the compensation committee and a member of the audit committee and executive committee of QuikTrip Corporation. Mr. Cropper has served as a director of Energy Transfer Partners GP since April 2000 and is a member of the independent committee, the litigation committee, the compensation committee, and the audit committee.
Bill W. Byrne. Mr. Byrne is the principal of Byrne & Associates, LLC, a gas liquids consulting group based in Tulsa, Oklahoma, and has held that position since 1992. Prior to that time, he served as Vice President of Warren Petroleum Company, the gas liquids division of Chevron Corporation, from 1982 to 1992. Mr. Byrne has served as a director of Energy Transfer Partners GP since 1992 and is a member of both the audit committee and the compensation committee. Mr. Byrne is a former president and director of the National Propane Gas Association (NPGA).
J. Charles Sawyer. Mr. Sawyer is the President and Chief Executive Officer of Sawyer Cellars. Mr. Sawyer is also the President and Chief Executive Officer of Computer Energy, Inc., a provider of computer software to the propane industry since 1981. Mr. Sawyer was Chief Executive Officer of Sawyer Gas Co., a regional propane distributor, until it was purchased by Heritage in 1991. Mr. Sawyer has served as a director of Energy Transfer Partners GP since 1991 and is a member of both the independent committee and the audit committee. Mr. Sawyer is a former president and director of the NPGA.
David R. Albin. Mr. Albin is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1988. Prior to his participation as a founding member of Natural Gas Partners, L.P. in 1988, he was a partner in the $600 million Bass Investment Limited Partnership. Prior to joining Bass Investment Limited Partnership, he was a member of the oil and gas group in the investment banking division of Goldman, Sachs & Co. Mr. Albin has served as a director of Energy Transfer Partners GP since February 2004.
Kenneth A. Hersh. Mr. Hersh is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. Mr. Hersh has served as a director of Energy Transfer Partners GP since February 2004.
Paul E. Glaske. Mr. Glaske retired as Chairman and Chief Executive Officer of Blue Bird Corporation, the largest manufacturer of school buses with manufacturing plants in three countries. Prior to becoming president of Blue Bird in 1986, Mr. Glaske served as the president of the Marathon LeTourneau Company, a manufacturer of large off-road mining and material handling equipment and off-shore drilling rigs. He currently is a member of the board of directors of the Texas Association of Business; SunTrust Bank, Middle Georgia, N.A.; Borg Warner
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Automotive, Inc.; and the U.S. Chamber of Commerce. Mr. Glaske has served as a director of Energy Transfer Partners GP since February 2004 and is chairman of the audit committee and a member of the independent committee. In addition, Mr. Glaske serves as the Vice-Chairman of the Natural Gas Vehicle Coalition.
K. Rick Turner. Mr. Turner is a Senior Vice President of Stephens Group, Inc., a family owned holding company with a diversified portfolio of investments. Stephens Group is the parent company of Stephens Inc., a co-managing underwriter of this offering. Mr. Turner has been employed by Stephens since 1990 and his areas of focus include oil and gas exploration, natural gas gathering and processing industries, and power technology. He currently serves as a director of Atlantic Oil Corporation; SmartSignal Corporation; Jebco Seismic, LLC; North American Energy Partners Inc.; and JV Industrial Companies, Ltd. Mr. Turner has served as a director of Energy Transfer Partners GP since February 2004 and is chairman of the compensation committee.
Ted Collins, Jr. Mr. Collins is an independent oil and gas producer. Mr. Collins previously served as President of Collins & Ware Inc. from 1988 to 2000, when its assets were sold to Apache Corporation. From 1982 to 1988, Mr. Collins was President of Enron Oil and Gas Company, and its predecessors, HNG Oil Company and HNG Internorth Exploration Co. From 1969 to 1982, Mr. Collins served as Executive Vice President of American Quaser Petroleum Company. Mr. Collins is a director and serves on the Finance Committee of Hanover Compression Company, and is a director and the Chairman of the Governance Committee of Encore Acquisition Company. Mr. Collins has served as a director of Energy Transfer Partners GP since August 2004.
John W. McReynolds. Mr. McReynolds is the President of Energy Transfer Equity and has served in that capacity since March 2005. He is also a director of Energy Transfer Partners. Prior to becoming President of Energy Transfer Equity, McReynolds was a partner with the international law firm of Hunton & Williams LLP, for over 20 years. As a lawyer, he specialized in energy-related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation and governmental proceedings, including as an expert in special projects for boards of directors of public companies.
Compensation of the General Partner
Energy Transfer Partners GP, the general partner of ETP does not receive any management fee or other compensation from ETP in connection with its management of ETP. Energy Transfer Partners GP and its affiliates performing services for ETP are reimbursed at cost for all expenses incurred on behalf of ETP, including the costs of employee compensation allocable to ETP, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, ETP. Following the Energy Transfer Transactions in January 2004, the employees of Energy Transfer Partners GP became employees of ETP’s Operating Partnership and as a result, Energy Transfer Partners GP has not incurred additional reimbursable costs since that time. Heritage incurred costs reimbursable to Energy Transfer Partners GP of $108.9 million for the year ended August 31, 2003 and $95.7 million for the year ended August 31, 2002.
Executive Compensation
ETP does not directly employ any of the persons responsible for managing or operating its business. Instead, it is managed by Energy Transfer Partners GP and its executive officers.
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The following table sets forth the annual salary, bonus and all other compensation awards and payouts for each of the past three fiscal years earned by: (i) all persons serving as the Chief Executive Officer of Energy Transfer Partner GP during fiscal year 2005; (ii) the four next highly compensated executive officers other than the Chief Executive Officer, who served as executive officers of Energy Transfer Partners GP during fiscal year 2004 and (iii) any persons who would have been reported had they been an executive officer of Energy Transfer Partners GP at the end of fiscal year 2005.
| Name and Principal Position |
Year |
Salary |
Bonus (3) |
Other Annual Compensation (4) |
All Other Compensation (5) | |||||||||
| Ray C. Davis Co-Chief Executive Officer (1) |
2005 2004 2003 |
$ |
443,462 120,000 — |
$ |
500,000 — — |
$ |
158 172 — |
$ |
— — — | |||||
| Kelcy L. Warren Co-Chief Executive Officer (1) |
2005 2004 2003 |
$ |
425,000 120,000 — |
$ |
500,000 — — |
$ |
552 172 — |
$ |
— — — | |||||
| H. Michael Krimbill President and Chief Financial Officer (2) |
2005 2004 2003 |
$ |
350,000 350,000 350,000 |
$ |
300,000 609,000 60,000 |
$ |
372 372 325 |
$ |
— 1,321,240 356,878 | |||||
| R. C. Mills Executive Vice President and Chief Operating Officer |
2005 2004 2003 |
$ |
335,000 335,000 335,000 |
$ |
100,000 594,000 60,000 |
$ |
2,052 2,052 2,052 |
$ |
— 1,321,240 356,878 | |||||
| Mackie McCrea Senior Vice President— Commercial Development |
2005 2004 2003 |
$ |
310,923 183,042 — |
$ |
174,000 248,000 — |
$ |
360 186 — |
$ |
— — — | |||||
| Robert A. Burk (6) Vice President—General Counsel and Secretary |
2005 2004 2003 |
$ |
226,538 200,000 — |
$ |
70,000 — — |
$ |
160 145 — |
$ |
— — — | |||||
| (1) | Messrs. Davis and Warren were named Co-Chief Executive Officers of Energy Transfer Partners GP in January of 2004. |
| (2) | Mr. Krimbill served as President and Chief Executive Officer of Energy Transfer Partners GP until January 2004. After the transactions with ETC OLP, Mr. Krimbill was elected President and Chief Financial Officer of Energy Transfer Partners GP. |
| (3) | Bonuses are earned based on the results of operations for each fiscal year. Bonuses for the 2004 fiscal year for Messrs. Krimbill, Mills, Atkinson, and Greenwood also include payments for the termination of their employment contracts in connection with the Energy Transfer Transaction. |
| (4) | Consists of life insurance premiums. |
| (5) | Consists of the value of ETP common units issued pursuant to awards under the Long-Term Incentive Compensation Plan, which terminated in conjunction with the Energy Transfer Transactions. |
| (6) | Mr. Burk was named Vice President—General Counsel of Energy Transfer Partners GP in February 2004. Mr. Burk’s salary for 2004 is annualized. |
Restricted Unit Plan
ETP previously adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, and amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan. (the “Restricted Unit Plan”) for certain directors and key employees of Energy Transfer Partners GP and its affiliates. The Restricted Unit Plan provided rights to acquire up to 146,000 common units of ETP. The Restricted Unit Plan provided for the award or grant to key employees of the right to acquire common units of ETP on such terms and conditions
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(including vesting conditions, forfeiture or lapse of rights) as the Compensation Committee of Energy Transfer Partners GP shall determine. In addition, eligible directors automatically received a director’s grant of to 500 common units of ETP on each September 1, and newly elected directors were also entitled to receive a grant of 2,000 common units of ETP upon election or appointment to the Board. Directors who were ETP’s employees or employees of its general partner were not entitled to receive a director’s grant of common units of ETP but could receive its common units as employees.
Generally, awards granted under the Restricted Unit Plan vested upon the occurrence of specified performance objectives established by ETP’s compensation committee at the time designations of grants were made, or if later, on the three-year anniversary of the grant date. In the event of a “change of control” (as defined in the Restricted Unit Plan), all rights to acquire ETP’s common units pursuant to the Restricted Unit Plan immediately vested. In connection with La Grange Energy’s acquisition of ETP’s general partner in January of 2004, all of the previous awards under the Restricted Unit Plan, except for awards for which waivers were granted thereunder or in conjunction with the employment agreement of the former Chairman of ETP’s general partner, vested.
The issuance of ETP’s common units pursuant to the Restricted Unit Plan was intended to serve as a means of incentive compensation, therefore, no consideration was payable by the plan participants upon vesting and issuance of the common units of ETP. As of August 31, 2005, 9,259 common units have been awarded and have not yet vested. Following the June 23, 2004 approval of the 2004 Unit Plan at a Special Meeting of the Unitholders the Restricted Unit Plan was terminated (except for the obligation to issue common units of ETP at the time the 9,259 Units previously awarded vest), and no additional grants will be made under the Restricted Unit Plan.
Long-Term Incentive Compensation Plan
Effective September 1, 2000, ETP adopted a long-term incentive compensation plan whereby ETP common units were to be awarded to the executive officers of its general partner upon achieving certain targeted levels of Distributed Cash (as defined in the Long-Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years Distributed Cash per ETP common unit. A minimum of 250,000 units and if targeted levels were achieved, a maximum of 500,000 units were available for award under the Long-Term Incentive Plan. Awards under the program were made starting in 2003 based upon the average of the prior three years Distributed Cash per unit. During the fiscal year ended August 31, 2003, 66,118 units vested pursuant to the vesting rights of the Long-Term Incentive Plan and ETP common units were issued. In connection with the acquisition by La Grange Energy of ETP’s general partner in January 2004, 150,018 units vested and common units of ETP were issued, and the Long-Term Incentive Plan terminated. Heritage recognized compensation expense of $0.6 million, $0.9 million, and $1.5 million for fiscal years 2004, 2003, and 2002, respectively.
2004 Unit Plan
On June 23, 2004 at a special meeting of the common unitholders of ETP, ETP’s common unitholders approved the terms of ETP’s 2004 Unit Plan, which provides for awards of common units of ETP and other rights to its employees, officers, and directors. The maximum number of common units of ETP that may be granted under the 2004 Unit Plan is 1,800,000 net units issued. Any awards that are forfeited or which expire for any reason, or any units which are not used in the settlement of an award will be available for grant under the 2004 Unit Plan. Units to be delivered upon the vesting of awards granted under the 2004 Unit Plan may be (i) units acquired by ETP in the open market, (ii) units already owned by ETP or its general partner, (iii) units acquired by ETP or its general partner directly from ETP, or any other person, (iv) units that are registered under a registration statement for the 2004 Unit Plan, (v) Restricted Units, or (vi) any combination of the foregoing.
Employee Grants. ETP’s compensation committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific
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general guidelines as defined by the 2004 Unit Plan. All outstanding awards shall fully vest into ETP common units upon any change in control as defined by the 2004 Unit Plan or upon such terms as the compensation committee may require at the time the award is granted. As of August 31, 2005, grants of awards totaling 265,600 units have been made to employees under the 2004 Unit Plan. These awards will vest subject to vesting over a three-year period based upon the achievement of certain performance criteria. Vested awards will convert into common units of ETP upon the third anniversary of the measuring date for the grants, which is September 1 of each year. Vesting occurs based upon the total return to ETP’s unitholders as compared to a group of MLP peers.
Director Grants. Each director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of Energy Transfer Partners, L.L.C., ETP, or a subsidiary (“Director Participant”), who is elected or appointed to the board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 4,000 ETP common units (the “Initial Director’s Grant”). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of ETP common units equal to $15,000 divided by the fair market value of a common unit of ETP on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest at the rate of 33% per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the 2004 Unit Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. As of August 31, 2005, Initial Director’s Grants totaling 2,000 units and annual grants totaling 4,844 units have been made.
Long-Term Incentive Grants. ETP’s compensation committee may, from time to time, grant awards under the 2004 Unit Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the 2004 Unit Plan. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the stock appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of August 31, 2005, there has been no Long-Term Incentive Grants made under the 2004 Unit Plan.
The 2004 Unit Plan is administered by ETP’s compensation committee of the Board of Directors and may be amended from time to time by the Board; provided however, that no amendment will be made without the approval of a majority of the unitholders of ETP (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the 2004 Unit Plan; (iii) materially increase the cost of the 2004 Unit Plan to ETP; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later than the 10th anniversary of its original effective date.
Compensation of Directors
ETP currently pays no additional remuneration to its employees who also serve as directors of its general partner. Prior to February 2004, ETP’s general partner paid each of its non-employee and nonaffiliated director $10,000 annually, plus $1,000 per board meeting attended and $500 per committee meeting attended. In addition, each of the members of the independent committee of ETP received a payment of $30,000 during fiscal year 2004, as payment for services and expenses rendered in conjunction with our evaluation of potential acquisition candidates. ETP will reimburse all expenses associated with the compensation of directors to its general partner.
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In February 2004, the disinterested members of ETP’s Board of Directors, approved the payment to eligible directors of an annual retainer of $20,000, plus $2,000 per board meeting attended, an additional annual payment of $5,000 to $7,500 for serving on designated committees, plus $1,000 per committee meeting attended, plus an Annual Director’s Grant as defined by the 2004 Unit Plan.
Equity Compensation Plan Information
At the time of its initial public offering, the shareholders of ETP’s general partner adopted the Restricted Unit Plan, which provided for the awarding of ETP common units to key employees. See “Executive Compensation—Restricted Unit Plan” for a description of the Restricted Unit Plan. At the June 23, 2004 special meeting of ETP’s common unitholders, common unitholders of ETP approved ETP’s 2004 Unit Plan, which provides for awards of common units of ETP and other rights to its employees, officers and directors and the Restricted Unit Plan was terminated except for its future obligation to issue common units that have not previously vested.
The following table sets forth in tabular format, a summary of certain information related to the equity compensation plans of ETP:
| Plan Category |
Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |
Weighted-average exercise price of outstanding options, warrants and rights (b) |
Number of securities column (a), (c) | |||
| Equity compensation plans approved by security holders: |
||||||
| Restricted Unit Plan |
9,259 | (1) $ 345,916 | — | |||
| 2004 Unit Plan |
276,835 | (1) 10,342,556 | 1,517,556 | |||
| Equity compensation plans not approved by security holders: |
— | — | — | |||
| Total (2) |
286,094 | $10,688,472 | 1,517,556 |
| (1) | Valued as of September 1, 2005. Actual exercise price may differ depending on the common unit price on the date such units vest. |
| (2) | As of August 31, 2005. |
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BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the beneficial ownership of our common units prior to and as of the closing of this offering by:
| • | each person who will beneficially own more than 5% of our common units; |
| • | each of the named executive officers of our general partner; |
| • | all of the directors of our general partner; and |
| • | all of the directors and executive officers of our general partner as a group. |
Beneficial ownership for the purposes of the following tables is defined by Rule 13d-3 under the Securities Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if they have or share the power to vote or direct the voting thereof (“Voting Power”) or to dispose or direct the disposition thereof (“Investment Power”) or have the right to acquire either of those powers within sixty (60) days. All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be.
| Common Units Beneficially Owned Prior to Offering |
Common Units Beneficially Owned After Offering | |||||
| Name of Beneficial Owner (1) |
Common Units |
Percent |
Percent | |||
| Ray C. Davis |
— | — | — | |||
| Kelcy L. Warren |
— | — | — | |||
| David R. Albin |
— | — | — | |||
| Kenneth A. Hersh |
— | — | — | |||
| Daniel Rioux (2) |
— | — | — | |||
| K. Rick Turner (3) |
— | — | — | |||
| John W. McReynolds (4) |
||||||
| Natural Gas Partners VI, L.P. (5) |
— | — | — | |||
| ETC Holdings, LP |
% | % | ||||
| Kellen Holding, LLC |
% | % | ||||
| Oasis Gas Partners LLC |
% | % | ||||
| Harvard Private Capital Properties III, Inc. |
% | % | ||||
| FHM Investments L.L.C. |
% | % | ||||
| All directors and executive officers of our general partner, as a group (7 individuals in total) |
||||||
| (1) | The address for Mr. McReynolds is 2828 Woodside Street, Dallas, Texas 95204. The address for Messrs. Davis and Warren and ETC Holdings is 2838 Woodside Street, Dallas, Texas 75204. The address for Mr. Albin is 100 North Guadalupe, Suite 205, Santa Fe, New Mexico 87501. The address for Mr. Rioux is 175 Berkeley Street, Boston, Massachusetts 02117. The address for Mr. Turner is 111 Center Street, Suite 2500, Little Rock, Arkansas 72201. The address for Kellen Holding, LLC is c/o Liberty Energy Corporation, 175 Berkeley Street, Boston, Massachusetts 02116. The address for Oasis Gas Partners LLC is c/o Stephens Group, Inc., 111 Center Street, Little Rock, Arkansas 72203. The address for Harvard Private Capital Properties is c/o Harvard Management Company, Inc., 600 Atlantic Ave, Boston, Massachusetts 02210. The address for FHM Investments is 7005 Quail Rock Lane, Reno, Nevada 89511. |
| (2) | A Voting and Transfer Restriction Agreement among certain of our limited partners and the owners of our general partner (the “Voting Agreement”) specifies that Kellen Holding, LLC has the right to designate one member of our board of directors. Mr. Rioux has been designated by Kellen Holding. Mr. Rioux disclaims any deemed beneficial ownership of our limited partner interests held by Kellen Holding. |
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| (3) | The Voting Agreement specifies that Oasis Gas Partners LLC has the right to designate one member of our board of directors. Mr. Turner has been designated by Oasis Gas Partners. Mr. Turner disclaims any deemed beneficial ownership of our limited partner interests held by Oasis Gas Partners. |
| (4) | Consists of Class B units that are convertible into common units on a one-for-one basis at the election of the holder. |
| (5) | Due to its ownership interests in ETC Holdings, LP, the NGP Fund may be deemed to beneficially own its pro rata share of the common units held by ETC Holdings, though such deemed ownership is not reflected in the table. |
The following table sets forth certain information as of September 1, 2005 regarding the beneficial ownership of ETP’s common units by:
| • | each person known by Energy Transfer Partners GP to beneficially own more than 5% of ETP’s common units; |
| • | each of the named executive officers of Energy Transfer Partners GP; |
| • | all of the directors of Energy Transfer Partners GP; and |
| • | all of the directors and executive officers of Energy Transfer Partners GP as a group. |
All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be. Each person has sole voting and dispositive power over the common units shown unless otherwise indicated below. Giving effect to ETE’s proposed acquisition of 3.64 million common units at the closing of this offering, ETP would have 110,524,572 common units outstanding at September 1, 2005.
| Title of Class |
Name and Address of Beneficial Owner (1) |
Beneficially Owned |
Percent of Class |
||||
| Common Units | Ray C. Davis (2) | 1,000 | * | ||||
| Kelcy L. Warren (2) | — | * | |||||
| H. Michael Krimbill (3) (5) | 722,118 | * | |||||
| Bill W. Byrne | 158,544 | * | |||||
| J. Charles Sawyer | 139,544 | * | |||||
| Stephen L. Cropper | 17,230 | * | |||||
| David R. Albin (4) | — | * | |||||
| Kenneth A. Hersh (4) | — | * | |||||
| Paul E. Glaske | 41,563 | * | |||||
| K. Rick Turner (4) | 4,063 | * | |||||
| Ted Collins, Jr. | 10,563 | * | |||||
| John W. McReynolds | 4,748 | * | |||||
| R.C. Mills (3) | 691,018 | * | |||||
| Mackie McCrea (2) | — | * | |||||
| Bradley K. Atkinson (5) | 109,200 | * | |||||
| Robert A. Burk (5) | — | * | |||||
| John Daigh (2) | — | * | |||||
| Karen Z. Hicks (5) | 4,510 | * | |||||
| All Directors and Executive Officers as a group (18 persons) | 1,904,101 | 1.72 | % | ||||
| Energy Transfer Equity, L.P. (6) | 36,413,840 | 33 | % | ||||
| FHM Investments, L.L.C. (5) | 1,308 | * | |||||
| Class C Units | FHS Investments, L.L.C. | 1,000,000 | 100 | % | |||
| Class E Units | Heritage Holdings, Inc. (7) | 8,853,832 | 100 | % |
| * | Less than one percent (1%) |
| (1) | The address for Energy Transfer Equity, L.P. and Mr. McReynolds is 2828 Woodside Street, Dallas, Texas 95204. The address for Messrs. Davis and Warren is 2838 Woodside Street, Dallas, Texas 75204. The address for Heritage Holdings and Messrs. Krimbill, Atkinson, Burk and Daigh is 8801 S. Yale Avenue, |
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| Suite 310, Tulsa, Oklahoma 74137. The address for Mr. McCrea is 800 E. Sonterra Blvd., San Antonio, Texas 78258. The address for Mr. Mills is 5000 Sawgrass Village, Suite 4, Ponte Vedra Beach, Florida 32082. The address for FHS Investments is 2215 B Renaissance Dr., Suite 5, Las Vegas, Nevada 89119. The address for FHM Investments is 7005 Quail Rock Lane, Reno, Nevada 89511. The address for Messrs. Byrne, Cropper, Collins, Glaske, Sawyer, and Turner is 2838 Woodside Street, Dallas, Texas 75204. |
| (2) | Due to the ownership of Messrs. Davis, Daigh, Warren, McCrea and FHM Investments in Energy Transfer Equity, L.P., they may be deemed to beneficially own the limited partnership interests held by Energy Transfer Equity, L.P. to the extent of their respective interests therein. Any such deemed ownership is not reflected in the table. |
| (3) | Each of Messrs. Mills, Cropper and Krimbill shares Voting and Investment Power on a portion of their respective units with his/her spouse. |
| (4) | Each of Messrs. Albin, Hersh, and Turner are representatives of or owners in entities owning interests in Energy Transfer Equity, L.P. and may be deemed to beneficially own the limited partnership interest held by Energy Transfer Equity, L.P., though such ownership is not depicted in the table. |
| (5) | Due to the ownership of Messrs. Atkinson, Burk and Krimbill and Ms. Hicks in FHM Investments, they may be deemed to beneficially own the limited partner interests held by FHM Investments to the extent of their respective interests therein and the limited partner interests held by Energy Transfer Equity, L.P. to the extent of FHM Investments’ respective interest therein. Any such deemed ownership is not reflected in the table. |
| (6) | Energy Transfer Equity, L.P. owns all of the member interests of Energy Transfer Partners, L.L.C., 100% of the Class A limited partner interest and 50% of the Class B limited partner interests in Energy Transfer Partners GP, L.P. Energy Transfer Partners, L.L.C. is the general partner of Energy Transfer Partners GP, L.P. with a .01% general partner interest. |
| (7) | Energy Transfer Partners, L.P. owns 100% of the common stock of Heritage Holdings, Inc. |
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Our Related Party Transactions
We own 100% of the Class A limited partner interests, 50% of the Class B limited partner interests and 100% of the general partner interests in Energy Transfer Partners GP, L.P., the general partner of ETP. Our cash flows currently consist of distributions from ETP related to the following partnership interests, including incentive distribution rights in ETP:
| • | our ownership of the 2% general partner interest in ETP, which we hold through our ownership interests in Energy Transfer Partners GP; |
| • | approximately 36.4 million common units of ETP, representing approximately 33% of the total outstanding common units of ETP, which we hold directly; and |
| • | 50% of the incentive distribution rights in ETP, which we likewise hold through our ownership interests in Energy Transfer Partners GP and which entitle us to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases. |
ETP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner. Since its initial public offering in 1996 and based on publicly issued guidance of ETP, ETP will have increased its quarterly distribution by 100%, from $0.25 per unit, or $1.00 per unit on an annualized basis, to, as of the distribution for the quarter ending August 31, 2005, $0.50 per unit, or $2.00 per unit on an annualized basis. Based on ETP’s current quarterly distribution of $0.50 per unit and the number of its common units outstanding at June 30, 2005, we would be entitled to receive a quarterly cash distribution of $26.4 million (or $105.6 million on an annualized basis), which consists of $1.5 million from our indirect ownership of the 2% general partner interest in ETP, $6.7 million from our indirect ownership of 50% of the incentive distribution rights in ETP and $18.2 million from the common units of ETP that we currently own.
The remaining 50% of the incentive distribution rights in ETP are held by Energy Transfer Investments, L.P. or ETI, through its ownership interests in Energy Transfer Partners GP. Our general partner, which is owned by Ray C. Davis, Kelcy L. Warren and Natural Gas Partners VI, L.P., also owns 100% of the general partner interest of the limited partnership that is the general partner of ETI.
Our general partner will receive a $500,000 per year management fee for the management of our operations and activities. Under the terms of the shared services agreement, we will also pay ETP an annual administrative fee of $500,000 for the provision of various general and administrative services for our benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from our general partner or its affiliates. In addition, our general partner will be reimbursed for direct and indirect expenses incurred on our behalf. Some of the non-independent directors of our general partner also serve as our directors.
In connection with this offering, certain of our and the general partner of ETP’s officers and directors, including Messrs. Davis and Warren, may purchase, in the aggregate, 1.5 million common units under our directed unit program. See “Underwriting.”
Related Party Transactions of ETP
ETP’s natural gas midstream operations secure compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities.” The ETG Entities were not acquired by ETP in conjunction with the Energy Transfer Transactions. The Co-Chief Executive Officers of ETP, Ray C. Davis and Kelcy L. Warren, have an indirect ownership and one of its directors Ted Collins, Jr., has an ownership interest in the ETG Entities. In addition, two of ETP’s directors, Ted Collins, Jr. and John W. McReynolds, serve on the board of directors of the ETG Entities. The terms of each arrangement to provide compression services are reviewed by the audit committee, and are no less favorable than those available from other providers of compression services. During fiscal year
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2004, payments totaling $279,000 were made by ETP to the ETG Entities for compression services provided to and utilized in our natural gas midstream operations.
One of ETP’s natural gas midstream subsidiaries owns a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is an entity in which one of our directors, Ted Collins, Jr. owns a 50% interest. ETP is the operator of the Dorado System. At August 31, 2004, there was a balance of $248,000 owing to ETP by this co-owner entity for services it provided as operator.
During the fiscal year ended August 31, 2004, payments of approximately $112,000 were made by ETP to the law firm of Hunton & Williams for legal services rendered. These services were provided to ETC OLP and ETP in connection with the Energy Transfer Transactions in January of 2004, and for the representation of ETC OLP in ongoing matters. John W. McReynolds, a director of the general partner of ETP since August 2004, was a partner in the Dallas, Texas office of Hunton & Williams, until March 2005.
Indemnification of Directors and Officers
Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director of officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership at the time of the occurrence giving rise to the indemnity being sought.
Material Provisions of Our General Partner’s Limited Liability Company Agreement
Our general partner’s management and operations are governed by its limited liability company agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part. The limited liability company agreement establishes a board of directors that will be responsible for the oversight of our business and operations. Our general partner’s board of directors will be comprised of directors upon closing of this offering and will be expanded to directors upon the appointment of two independent directors following the closing of this offering.
The limited liability company agreement also provides that our general partner’s board of directors will elect the officers of our general partner, and the limited liability company agreement establishes the powers and duties of these officers.
The limited liability company agreement also provides the structure for how distributions and allocations of profits and losses will be made to members of our general partner.
In connection with the closing of this offering, we will enter into a shared services agreement between Energy Transfer Partners GP and ETP. Under the shared services agreement, certain personnel of ETP will perform administrative and commercial services for us. The services performed by these personnel will include, but not be limited to, financial, accounting, administrative, legal and other services. ETP will provide these services either though its own resources, the resources of its subsidiaries or affiliates or by contracting with independent contractors. Under the terms of the shared services agreement, we will also pay ETP an annual administrative fee of $500,000 for the provision of various general and administrative services for our benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from our general partner or its affiliates. The shared services agreement requires that the parties develop an annual operating plan, setting forth specific objectives, standards, performance measures and activities as well as a budget for the services to be provided under the plan. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us and ETP.
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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
General. Conflicts of interest exist and may arise in the future as a result of the relationships among us, ETP and our and their respective general partners and affiliates. The owners of our general partner are Ray C. Davis, Kelcy L. Warren and Natural Gas Partners VI, L.P. These owners also control Energy Transfer Investments, L.P., which holds 50% of the incentive distribution rights in ETP through its ownership of equity interests in Energy Transfer Partners GP. Natural Gas Partners VI, L.P., which we refer to as the “NGP Fund,” is a private equity fund that owns a significant portion of our equity securities and has the right to appoint two directors to the board of directors of our general partner. Mr. Davis and Mr. Warren are the co-chairmen and co-chief executive officers of ETP and also own significant portions of the entities that hold our equity securities. The NGP Fund, Mr. Davis and Mr. Warren have all been involved with ETE since our inception in 2002. Because of their total current majority ownership interests, Messrs. Davis and Warren and the NGP Fund collectively have the ability to elect, remove and replace the directors and officers of our general partner.
Our general partner’s directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. Our general partner’s directors also have fiduciary duties to its equity owners. Some of the non-independent directors of our general partner also serve as directors of Energy Transfer Partners GP and, as a result, have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and its partners. Consequently, these directors may encounter situations in which their fiduciary obligations to ETP, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
Shared Personnel. Our general partner will manage our operations and activities. In connection with the closing of this offering, we will enter into a shared services agreement between Energy Transfer Partners GP and ETP. Under the shared services agreement, personnel of ETP will perform administrative and commercial services for us. The services performed by these personnel will include, but not be limited to, financial, accounting, administrative, legal and other services. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us and ETP. For a more detailed description of our shared services agreement, please read “Certain Relationships and Related Party Transactions—Shared Services Agreement.”
Conflicts Between Our General Partner and its Affiliates and Our Partners. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:
| • | approved by the audit and conflicts committee, although our general partner is not obligated to seek such approval; |
| • | approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner or any of its affiliates; |
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
Our general partner may, but is not required to, seek the approval of such resolution from the audit and conflicts committee of its board of directors. If our general partner does not seek approval from the audit and
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conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the audit and conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.
Conflicts of interest could arise in the situations described below, among others.
Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.
The amount of cash that is available for distribution to our unitholders is affected by decisions of our general partner regarding such matters as:
| • | amount and timing of cash expenditures; |
| • | assets sales or acquisitions; |
| • | borrowings; |
| • | the issuance of additional units; and |
| • | the creation, reduction or increase of reserves in any quarter. |
Neither we nor ETP will be prohibited from competing with each other.
Neither our partnership agreement nor the partnership agreement of ETP prohibits us from owning assets or engaging in businesses that compete directly or indirectly with ETP or prohibit ETP from owning assets or engaging in businesses that compete directly or indirectly with us, except that ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, we may acquire, construct or dispose of any assets in the future without any obligation to offer ETP the opportunity to purchase or construct any of those assets, and ETP may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of these assets. Please read “Certain Relationships and Related Party Transactions.”
We will reimburse our general partner and its affiliates for expenses.
We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Please read “Certain Relationships and Related Party Transactions.”
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
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Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.
Our partnership agreement allows our general partner to determine any amounts to reimburse itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm’s-length negotiations.
Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the units offered in this offering.
Our units are subject to our general partner’s limited call right.
If at any time our general partner and its affiliates own more than 90% of the units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. At the completion of this offering and assuming no exercise of the over-allotment option, our general partner and its affiliates will own approximately 86.6% of our outstanding common units and Class B units. Please read “Description of Our Partnership Agreement—Limited Call Right.”
We may not choose to retain separate counsel for ourselves or for the holders of our units.
The attorneys, independent auditors and others who have performed services for us regarding the offering have been retained by our general partner, its affiliates and us and may continue to be retained by our general partner, its affiliates and us after the offering. Attorneys, independent auditors and others who will perform services for us in the future will be selected by our general partner or our audit and conflicts committee and may also perform services for our general partner and its affiliates. We may, but are not required to, retain separate counsel for ourselves or the holders of units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of units, on the other, after the sale of the units offered in this prospectus, depending on the nature of the conflict. We do not intend to do so in most cases.
Our general partner’s affiliates may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Certain Relationships and Related Party Transactions—Shared Services Agreement.”
Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict, eliminate or otherwise modify the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.
Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. These modifications are detrimental to the unitholders because they restrict the remedies available to unitholders
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for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
| State law fiduciary duty standards |
Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present. |
| Partnership agreement modified standards |
Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held. |
| Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the audit and conflicts committee of the board of directors of our general partner must be: |
| • on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). |
| If our general partner does not seek approval from the audit committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held. |
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| In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud, willful misconduct or gross negligence. |
| Rights and remedies of unitholders |
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. |
Our partnership agreement also specifically permits us to engage in any activity, including those that may be in direct competition with ETP except that, due to provisions in the existing partnership agreement of ETP, we will be prohibited from engaging in the retail propane business in the United States. As a result, we may acquire, construct or dispose of natural gas midstream, transportation and storage or propane assets without any obligation to offer ETP the opportunity to acquire those assets. Currently, ETP is not prohibited from engaging in any activity that may compete with us. In the event that we desire to sell any assets to ETP, the corporate governance policies of ETP provides that no such sale may occur unless the purchase by ETP is approved by the audit committee of the ETP (a committee which satisfies the independent requirements of the New York Stock Exchange) or the purchase by ETP is equitable to ETP, taking into account the totality of the relationships between the parties.
In order to become one of our limited partners, a unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
We are required to indemnify our general partner and its officers, directors, and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. Indemnification is also required for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. In the opinion of the Commission, indemnification provisions that purport to include indemnification for liabilities arising under the Securities Act are contrary to public policy and are, therefore, unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read “Description of Our Partnership Agreement—Indemnification.”
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Generally, our common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units, class B units and our general partner in and to cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”
We have filed an application to list our outstanding common units on the NYSE under the symbol “ETE.” Any additional common units we issue will also be listed on the NYSE.
American Stock Transfer & Trust Company will serve as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of units, except the following that must be paid by unitholders:
| • | surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges; |
| • | special charges for services requested by a holder of a common unit; and |
| • | other similar fees or charges. |
There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
By transfer of our common units in accordance with our partnership agreement, each transferee of our common units will be admitted as a unitholder with respect to the common units transferred when such transfer and admission is reflected in our books and records. Additionally, each transferee of our common units:
| • | represents that the transferee has the capacity, power and authority to become bound by our partnership agreement; |
| • | automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and |
| • | gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering. |
An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. The general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
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Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
As of the closing of this offering, we will have Class B units outstanding. These units will be issued under our Class B Unit Incentive Plan. Each Class B unit will represent a limited partner interest in us and will be entitled to receive quarterly cash distributions in the same amount as the quarterly cash distributions we make on each common unit. Each Class B unit will be allocated a portion of our income, gain, loss, deduction and credit on a pro rata basis with each common unit, and each Class B unit will be entitled to receive distributions upon liquidation in the same manner as each common unit. Each Class B unit will also have the same voting rights as a common unit. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit. The Class B units will not be subject to vesting. The Class B units, unlike the common units, will have a zero initial capital account balance.
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DESCRIPTION OF OUR PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus.
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
| • | with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions;” |
| • | with regard to rights of holders of units, please read “Description of Our Common Units;” and |
| • | with regard to allocations of taxable income and other matters, please read “Material Tax Consequences.” |
We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. In February 2004, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name to Energy Transfer Equity, L.P. We have a perpetual existence.
Under our partnership agreement, we are permitted to engage, directly or indirectly, in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law, provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. For a further description of limits on our business, please read “Certain Relationships and Related Party Transactions.”
Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “—Amendments to Our Partnership Agreement.”
Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
| • | to remove or replace the general partner; |
| • | to approve some amendments to the partnership agreement; or |
| • | to take other action under the partnership agreement; |
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the
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general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. While we currently have no operations distinct from ETP, if in the future, by our ownership in an operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
The following is a summary of the unitholder vote required for the matters specified below. In voting their units, affiliates of our general partner will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
| Issuance of additional units | No approval right. | |
| Amendment of our partnership agreement | Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of a majority of our outstanding units. Please read “—Amendments to Our Partnership Agreement.” | |
| Merger of our partnership or the sale of all or substantially all of our assets | A majority of our outstanding units in certain circumstances. Please read “—Merger, Sale or Other Disposition of Assets.” | |
| Dissolution of our partnership | A majority of our outstanding units. Please read “—Termination or Dissolution.” | |
| Reconstitution of our partnership upon dissolution | A majority of our outstanding units. Please read “—Termination or Dissolution.” | |
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| Withdrawal of our general partner | Under most circumstances, the approval of a majority of the units, excluding units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to June 30, 2015 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.” | |
| Removal of our general partner | Not less than 66 2/3 of the outstanding units, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.” | |
| Transfer of the general partner interest | Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other than an individual) or (ii) another entity in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the units, excluding units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to , 2015. Please read “—Transfer of General Partner Interest.” | |
| Transfer of ownership interests in our general partner | No approval required at any time. Please read “—Transfer of Ownership Interests in Our General Partner.” | |
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that are equal in rank with or junior to our units on terms and conditions established by our general partner in its sole discretion without the approval of our unitholders.
It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which units are not entitled.
Upon issuance of additional units or other partnership securities, our general partner will have the option but not the obligation to make additional capital contributions to the extent it desires to maintain its general partner interest in us. Our general partner and its affiliates have the right, which they may from time to time assign in whole or in part to any of their affiliates, to purchase units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain their percentage interests in us that existed immediately prior to the issuance. Our general partner and its affiliates will hold approximately 86.6% of our outstanding common units and Class B units after this offering. The holders of units will not have preemptive rights to acquire additional units or other partnership interests in us.
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Amendments to Our Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of our outstanding units.
Prohibited Amendments
No amendment may be made that would:
| (1) | enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or |
| (2) | enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option. |
The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units.
No Unitholder Approval
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
| (1) | a change in the name of the partnership, the location of the partnership’s principal place of business, the partnership’s registered agent or its registered office; |
| (2) | the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement; |
| (3) | a change that, in the sole discretion of our general partner, is necessary or advisable for the partnership to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; |
| (4) | an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed; |
| (5) | any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone; |
| (6) | an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement; |
| (7) | any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by the partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement; |
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| (8) | a change in our fiscal year or taxable year and related changes; |
| (9) | certain mergers or conveyances set forth in our partnership agreement; and |
| (10) | any other amendments substantially similar to any of the matters described in (1) through (9) above. |
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee in connection with a merger or consolidation approved in accordance with our partnership agreement, or if our general partner determines that those amendments:
| (1) | do not adversely affect our limited partners in any material respect; |
| (2) | are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; |
| (3) | are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the partnership’s best interest and the best interest of our limited partners; |
| (4) | are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or |
| (5) | are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement. |
Opinion of Counsel and Unitholder Approval
Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described under “—Amendments to Our Partnership Agreement—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.
Merger, Sale or Other Disposition of Assets
Our partnership agreement generally prohibits our general partner, without the prior approval of a majority of our outstanding units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.
If conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.
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We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
| (1) | the election of our general partner to dissolve us, if approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates; |
| (2) | there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law; |
| (3) | the entry of a decree of judicial dissolution of our partnership; or |
| (4) | the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor. |
Upon a dissolution under clause (4) above, the holders of a majority of our outstanding units may also elect, excluding any units held by our general partner and its affiliates, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing a successor general partner an entity approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates, subject to receipt by us of an opinion of counsel to the effect that:
| • | the action would not result in the loss of limited liability of any limited partner; and |
| • | none of our partnership nor the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue. |
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:
| • | first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and |
| • | then, to all partners in accordance with the positive balance in the respective capital accounts. |
Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.
Withdrawal or Removal of Our General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2015 without obtaining the approval of a majority of our outstanding units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2015, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates.
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Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.
Our general partner may not be removed unless that removal is approved by not less than 66 2/3% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of such removal, our general partner will have the right to convert its general partner interest into units or to receive cash in exchange for such interests. Any removal of this kind is also subject to the approval of a successor general partner by a majority of our outstanding units, including those held by our general partner and its affiliates. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. Upon completion of this offering, affiliates of our general partner will own approximately 86.6% of the outstanding common units on a fully diluted basis.
In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interest
Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:
| • | an affiliate of the general partner (other than an individual); or |
| • | another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all or substantially all of its assets to another entity, |
our general partner may not transfer all or any part of its general partner interest in us to another entity prior to without the approval of a majority of the units outstanding, excluding units held by our general partner
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and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
Our general partner and it affiliates may at any time transfer units to one or more persons without unitholder approval.
Transfer of Ownership Interests in Our General Partner
At any time, Ray C. Davis, Kelcy L. Warren and the NGP Fund, as the members of our general partner, may sell or transfer all or part of their ownership interest in the general partner without the approval of our unitholders.
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner as general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.
If at any time our general partner and its affiliates hold more than 90% of the outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:
| • | the highest cash price paid by either our general partner or any of its affiliates for any limited partners interests of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase the limited partner interests; and |
| • | the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed. |
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences—Disposition of Units.”
Upon completion of this offering, affiliates of our general partner will own 100,560,000 of our common units units on a fully diluted basis, representing approximately 86.6% of our outstanding units.
Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by non-citizen assignees will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.
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Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
By transfer of units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the transferred units when such transfer and admission is reflected in our books and records. Except as described under “—Limited Liability,” the units will be fully paid, and unitholders will not be required to make additional contributions.
Non-Citizen Assignees; Redemption
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
| (1) | our general partner; |
| (2) | any departing general partner; |
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| (3) | any person who is or was an affiliate of our general partner or any departing general partner; |
| (4) | any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above; |
| (5) | any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of the general partner or any departing general partner; and |
| (6) | any person designated by our general partner. |
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.
Our general partner will receive a management fee of $500,000 for its management of Energy Transfer Equity. Under the terms of the shared services agreement, we will pay ETP an annual administrative fee of $500,000 and will reimburse ETP at cost for all services to us for the provision of various general and administrative services for our benefit.
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
Right to Inspect Our Books and Records
A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, obtain:
| • | a current list of the name and last known address of each partner; |
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| • | a copy of our tax returns; |
| • | information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner; |
| • | copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement; |
| • | information regarding the status of our business and financial condition; and |
| • | any other information regarding our affairs as is just and reasonable. |
Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”
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ENERGY TRANSFER PARTNERS’ CASH DISTRIBUTION POLICY
Following is a description of the relative rights and preferences of holders of ETP’s common units and ETP’s general partner in and to cash distributions.
Distributions of Available Cash
General. ETP distributes all of its “available cash” to its unitholders and its general partner within 45 days following the end of each fiscal quarter.
Definition of Available Cash. Available cash of ETP is defined in ETP’s partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:
| • | less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner of ETP to: |
| • | provide for the proper conduct of its business; |
| • | comply with applicable law or any debt instrument or other agreement (including reserves for future capital expenditures and for its future credit needs); or |
| • | provide funds for distributions to ETP’s unitholders and its general partner in respect of any one or more of the next four quarters; |
| • | plus all of ETP’s cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings of ETP made after the end of the quarter. Working capital borrowings are generally borrowings that are made under ETP’s credit facilities and in all cases are used solely for working capital purposes or to pay distributions to ETP’s partners. |
Operating Surplus and Capital Surplus
General. All cash distributed to ETP’s unitholders is characterized as either “operating surplus” or “capital surplus.” ETP distributes available cash from operating surplus differently than its available cash from capital surplus.
Definition of Operating Surplus. ETP’s operating surplus for any period generally means:
| • | its cash balance on the closing date of its initial public offering in 1996; plus |
| • | $10.0 million (as described below); plus |
| • | all of ETP’s cash receipts since the closing of its initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus |
| • | ETP’s working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less |
| • | all of ETP’s operating expenditures after the closing of its initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less |
| • | the amount of ETP’s cash reserves that the general partner of ETP deems necessary or advisable to provide funds for future operating expenditures. |
Definition of Capital Surplus. Generally, ETP’s capital surplus will be generated only by:
| • | borrowings other than working capital borrowings; |
| • | sales of ETP’s of debt and equity securities; and |
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| • | ETP’s sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets. |
Characterization of Cash Distributions. ETP treats all of its available cash distributed as coming from its operating surplus until the sum of all available cash distributed since it began operations equals the operating surplus as of the most recent date of determination of available cash. ETP treats any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million in addition to its cash balance on the closing date of its initial public offering in 1996, cash receipts from its operations and cash from working capital borrowings. This amount does not reflect actual cash on hand that is available for distribution to its unitholders. Rather, it is a provision that will enables ETP, if it chooses, to distribute as operating surplus up to $50.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We have not made, and we do not anticipate that we will make, any distributions from capital surplus.
ETP’s incentive distribution rights represent the contractual right of the general partner of ETP to receive a specified percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution has been paid by ETP. Please read “—Distributions of Available Cash from Operating Surplus” below. ETP’s general partner owns all of the incentive distribution rights, except that in conjunction with the August 2000 transaction with U.S. Propane, L.P., ETP issued 1,000,000 class C units to Heritage Holdings, its general partner at that time, in conversion of that portion of Heritage Holdings’ incentive distribution rights that entitled it to receive any distribution made by ETP of funds attributable to the net amount received by ETP in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation. In January 2004, the class C units were distributed by Heritage Holdings to the owners of its equity interests, and, as a result, neither ETP nor any of its subsidiaries own any of the outstanding class C units. Any amount payable on the class C units in the future will reduce the amount otherwise distributable to holders of ETP’s incentive distribution rights at the time the distribution of such litigation proceeds is made and will not reduce the amount distributable to holders of ETP’s common units. No payments to date have been made on the class C units.
Distributions of Available Cash from Operating Surplus
ETP is required to make distributions of its available cash from operating surplus for any quarter in the following manner:
| • | First, 98% to all common and class E unitholders of ETP, in accordance with their percentage interests, and 2% to the general partner, until each common unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”); |
| • | Second, 98% to all common and class E unitholders of ETP, in accordance with their percentage interests, and 2% to the general partner, until each common unit has received $0.275 per unit for such quarter (the “first target cash distribution”); |
| • | Third, 85% to all common and class E unitholders of ETP, in accordance with their percentage interests, 13% to the holders of incentive distribution rights, pro rata, and 2% to the general partner, until each common unit has received $0.3175 per unit for such quarter (the “second target cash distribution”); |
| • | Fourth, 75% to all common and class E unitholders of ETP, in accordance with their percentage interests, 23% to the holders of incentive distribution rights, pro rata, and 2% to the general partner, until each common unit has received $0.4125 per unit for such quarter (the “third target cash distribution”); and |
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| • | Fifth, thereafter, 50% to all common and class E unitholders of ETP, in accordance with their percentage interests, 48% to the holders of incentive distribution rights, pro rata, and 2% to the general partner. |
Notwithstanding the foregoing, the distributions on each class E unit of ETP may not exceed $1.41 per year.
Distributions of Available Cash from Capital Surplus
ETP will make distributions of its available cash from capital surplus, if any, in the following manner:
| • | First, 98% to all of its unitholders, pro rata, and 2% to its general partner, until ETP distributes for each ETP common unit, an amount of available cash from capital surplus equal to its initial public offering price; |
| • | Thereafter, ETP will make all distributions of its available cash from capital surplus as if they were from operating surplus. |
ETP’s partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price per ETP common unit less any distributions of capital surplus per unit is referred to as the “unrecovered capital” of ETP.
If ETP combines its units into fewer units or subdivide its units into a greater number of units, ETP will proportionately adjust its minimum quarterly distribution; its target cash distribution levels; and its unrecovered capital.
For example, if a two-for-one split of the common units of ETP should occur, the unrecovered capital of ETP would each be reduced to 50% of its initial level. ETP will not make any adjustment by reason of its issuance of additional units for cash or property.
On January 14, 2005, ETP’s general partner announced a two-for-one split of its common units that was effected on March 15, 2005. As a result, the minimum quarterly distribution and the target cash distribution levels of ETP were reduced to 50% of their initial levels. The adjusted minimum quarterly distribution and the adjusted target cash distribution levels of ETP are reflected in the discussion above under the caption “Distributions of Available Cash from Operating Surplus.”
In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes ETP to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, ETP will reduce its minimum quarterly distribution and the target cash distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates.
Distributions of Cash Upon Liquidation
General. If ETP dissolves in accordance with its partnership agreement, it will sell or otherwise dispose of its assets in a process called liquidation. ETP will first apply the proceeds of its liquidation to the payment of its creditors. ETP will distribute any remaining proceeds to its unitholders and its general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of its assets in liquidation.
Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of ETP’s general partner.
Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in ETP’s partnership agreement in the following manner:
| • | First, to the general partner and the holders of units of ETP who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; |
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| • | Second, 98% to the common unitholders of ETP, pro rata, and 2% to the general partner of ETP, until the capital account for each common unit is equal to the sum of: |
| • | its unrecovered capital; and |
| • | the amount of the minimum quarterly distribution of ETP for the quarter during which our liquidation occurs; |
| • | Third, 98% to all unitholders of ETP, pro rata, and 2% to the general partner of ETP, until we allocate under this paragraph an amount per ETP unit equal to: |
| • | the sum of the excess of the first target cash distribution per ETP unit over the minimum quarterly distribution per ETP unit for each quarter of our existence; less |
| • | the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the minimum quarterly distribution per ETP unit that it distributed 98% to its unitholders, pro rata, and 2% to its general partner, for each quarter of its existence; |
| • | Fourth, 85% to all unitholders of ETP, pro rata, 13% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP, until ETP allocates under this paragraph an amount per ETP unit equal to: |
| • | the sum of the excess of the second target cash distribution per ETP unit over the first target cash distribution per ETP unit for each quarter of ETP’s existence; less |
| • | the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the first target cash distribution per ETP unit that it distributed 85% to the unitholders of ETP, pro rata, 13% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP for each quarter of its existence; |
| • | Fifth, 75% to all unitholders of ETP, pro rata, 23% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP, until ETP allocates under this paragraph an amount per ETP unit equal to: |
| • | the sum of the excess of the third target cash distribution per ETP unit over the second target cash distribution per ETP unit for each quarter of its existence; less |
| • | the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the second target cash distribution per ETP unit that it distributed 75% to the unitholders of ETP, pro rata, 23% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP for each quarter of its existence; and |
| • | Sixth, thereafter, 50% to all unitholders of ETP, pro rata, 48% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP. |
Manner of Adjustments for Losses. Upon ETP’s liquidation, ETP will generally allocate any loss to its general partner and its unitholders in the following manner:
| • | First, 98% to the holders of common units of ETP in proportion to the positive balances in their capital accounts and 2% to the general partner of ETP, until the capital accounts of the common unitholders of ETP have been reduced to zero; and |
| • | Second, thereafter, 100% to the general partner of ETP. |
Adjustments to Capital Accounts upon the Issuance of Additional Units. ETP will make adjustments to its capital accounts upon its issuance of additional units. In doing so, ETP will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to its unitholders and its general partner in the same manner as it allocates gain or loss upon liquidation. In the event that ETP makes positive adjustments to its capital accounts upon its issuance of additional units, ETP will allocate any later negative adjustments to its capital accounts resulting from its issuance of additional units or upon its liquidation in a manner which results, to the extent possible, in its general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to its capital accounts had been made.
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ENERGY TRANSFER PARTNERS’ PARTNERSHIP AGREEMENT
The following is a summary of material provisions of ETP’s partnership agreement. For more information on distributions of ETP’s available cash, please read “Energy Transfer Partners’ Cash Distribution Policy.”
ETP unitholders do not have voting rights except with respect to the following matters, for which ETP’s partnership agreement requires the approval of the holders of a majority of the units, unless otherwise indicated:
| • | a merger of ETP; |
| • | a sale or exchange of all or substantially all of the assets of ETP; |
| • | dissolution or reconstitution of ETP upon dissolution; |
| • | certain amendments to ETP’s partnership agreement; |
| • | the transfer to another person of ETP’s general partner interest before June 30, 2006 or the incentive distribution rights at any time, except for transfers to affiliates of the general partner or transfers in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person; and |
| • | the withdrawal of the general partner prior to June 30, 2006 in a manner that would cause the dissolution of ETP. |
The removal of ETP’s general partner requires the approval of not less than 66 2/3% of all outstanding units, including units held by its general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by ETP’s general partner and its affiliates.
Issuance of Additional Securities
ETP’s partnership agreement authorizes it to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by its general partner in its general partners’ sole discretion, without the approval of the unitholders. Any such additional partnership securities may be senior to the common units.
It is possible that ETP will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units ETP issues will be entitled to share equally with the then-existing holders of its common units in its distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in ETP’s net assets.
In accordance with Delaware law and the provisions of its partnership agreement, ETP may also issue additional partnership securities that, in the sole discretion of the general partner, may have special voting rights to which common units are not entitled.
Upon issuance of additional partnership securities, ETP’s general partner will be required to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in ETP. Moreover, ETP’s general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase ETP’s common units or other equity securities whenever, and on the same terms that, ETP issues those securities to persons other than its general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by ETP’s common units, that existed immediately prior to each issuance. The holders of ETP’s common units will not have preemptive rights to acquire additional common units or other partnership securities.
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The following matters require the approval of the majority of the outstanding common units, including the common units owned by the general partner and its affiliates:
| • | a merger of our partnership; |
| • | a sale or exchange of all or substantially all of our assets; |
| • | dissolution or reconstitution of our partnership upon dissolution; |
| • | certain amendments to the partnership agreement; |
| • | the transfer to another person of our general partner interest before June 30, 2006 or the incentive distribution rights at any time, except for transfers to affiliates of the general partner or transfers in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person; and |
| • | the withdrawal of the general partner prior to June 30, 2006 in a manner that would cause the dissolution of our partnership. |
The removal of our general partner requires the approval of not less than 66 2/3% of all outstanding units, including units held by our general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by our general partner and its affiliates.
ETP’s general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, ETP issues those securities to persons other than its general partner and its affiliates, to the extent necessary to maintain their percentage interests in ETP that existed immediately prior to the issuance. The holders of ETP’s common units will not have preemptive rights to acquire additional common units or other partnership securities in it.
Amendments to ETP’s Partnership Agreement
Amendments to ETP’s partnership agreement may be proposed only by ETP’s general partner. Certain amendments require the approval of a majority of the outstanding common units, including common units owned by the general partner and its affiliates. Any amendment that materially and adversely affects the rights or preferences of any class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the class of limited partnership interests so affected. However, in some circumstances, more particularly described in ETP’s partnership agreement, ETP’s general partner may make amendments to ETP’s partnership agreement without the approval of ETP’s unitholders to reflect:
| • | a change in ETP’s name, the location of its principal place of business, its registered agent or its registered office; |
| • | the admission, substitution, withdrawal or removal of partners; |
| • | a change to qualify or continue ETP’s qualification as a limited partnership or a partnership in which its limited partners have limited liability under the laws of any state or to ensure that neither ETP or HOLP will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes; |
| • | a change that does not adversely affect ETP’s unitholders in any material respect; |
| • | a change to (i) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, (ii) facilitate the trading of ETP’s common units or comply with any rule, regulation, guideline or requirement of any national securities exchange on which its common units are or will be listed for trading (iii) that is necessary or advisable in connection with action taken by ETP’s general partner with respect to subdivision and combination of its securities or (iv) that is required to effect the intent expressed in ETP’s partnership agreement; |
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| • | a change in ETP’s fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in its fiscal year or taxable year; |
| • | an amendment that is necessary to prevent ETP, or its general partner or its general partner’s directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended; |
| • | an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of ETP’s securities; |
| • | any amendment expressly permitted in ETP’s partnership agreement to be made by its general partner acting alone; |
| • | an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with its partnership agreement; |
| • | an amendment that is necessary or advisable to reflect, account for and deal with appropriately ETP’s formation of, or investment in, any corporation, partnership, joint venture, limited liability company or other entity other than its operating partnership, in connection with its conduct of activities permitted by its partnership agreement; |
| • | a merger or conveyance to effect a change in ETP’s legal form; or |
| • | any other amendments substantially similar to the foregoing. |
Merger, Sale or Other Disposition of Assets
ETP’s general partner is generally prohibited, without the prior approval of the holders of at least a majority of the outstanding common units (excluding common units held by the general partner and its affiliates), from causing ETP to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions or approving on behalf of ETP the sale, exchange or other disposition of all or substantially all of the assets of its operating partnership; provided that its general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of ETP or its operating partnership without such approval. ETP’s general partner may also sell all or substantially all of ETP’s assets or its operating partnership’s assets pursuant to a foreclosure or other realization upon the foregoing encumbrances without such approval. Furthermore, provided that certain conditions are satisfied, the ETP’s general partner may merge ETP or any member of its partnership group into, or convey some or all of the partnership group’s assets to, a newly-formed entity if the sole purpose of such merger or conveyance is to effect a mere change in the legal form of ETP into another limited liability entity. ETP’s unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation of ETP, a sale of substantially all of ETP’s assets or any other transaction or event.
ETP will continue as a limited partnership until terminated under its partnership agreement. ETP will dissolve upon:
| (1) | the expiration of ETP’s term under its partnership agreement; |
| (2) | the election of ETP’s general partner to dissolve ETP, if approved by the holders of a majority of ETP’s outstanding common units, excluding those common units held by ETP’s general partner and its affiliates; |
| (3) | the sale, exchange or other disposition of all or substantially all of ETP assets and properties and those of its subsidiaries; |
| (4) | the entry of a decree of judicial dissolution of ETP; or |
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| (5) | the withdrawal or removal of ETP’s general partner or any other event that results in its ceasing to be ETP’s general partner other than by reason of a transfer of its general partner interest in accordance with ETP’s partnership agreement or withdrawal or removal following approval and admission of a successor. |
Upon a dissolution under clause (5) above, the holders of a majority of ETP’s common outstanding units (excluding those common units held by ETP’s general partner and its affiliates) may also elect, within specific time limitations, to reconstitute ETP and continue its business on the same terms and conditions described in its partnership agreement by forming a new limited partnership on terms identical to those in ETP’s partnership agreement and having as general partner an entity approved by the holders of a majority of ETP’s outstanding common units, excluding those common units held by ETP’s general partner and its affiliates, subject to receipt by ETP of an opinion of counsel to the effect that:
| • | the action would not result in the loss of limited liability of any limited partner; and |
| • | none of the partnership, the reconstituted limited partnership, ETP’s operating partnership nor any of its other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue. |
Liquidation and Distribution of Proceeds
Upon ETP’s dissolution, unless it is reconstituted and continued as a new limited partnership, the person authorized to wind up ETP’s affairs (the liquidator) will, acting with all the powers of ETP’s general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate ETP’s assets. The proceeds of the liquidation will be applied as follows:
| • | first, towards the payment of all of ETP’s creditors and the creation of a reserve for contingent liabilities; and |
| • | then, to all partners in accordance with the positive balance in the respective capital accounts. |
Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of ETP’s assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to ETP’s partners, ETP’s general partner may distribute assets in kind to ETP’s partners.
Withdrawal or Removal of ETP’s General Partner
ETP’s general partner has agreed not to withdraw voluntarily as ETP’s general partner prior to December 1, 2006 without obtaining the approval of the holders of a majority of ETP’s outstanding common units, excluding those held by ETP’s general partner and its affiliates, and furnishing an opinion of counsel stating that such withdrawal (following the selection of the successor general partner) would not result in the loss of the limited liability of any of ETP’s limited partners or of the limited partner of ETP’s operating partnership or cause ETP or its operating partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such).
On or after December 31, 2006, ETP’s general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of ETP’s partnership agreement. In addition, ETP’s general partner may withdraw without unitholder approval upon 90 days’ notice to ETP’s limited partners if at least 50% of ETP’s outstanding common units are held or controlled by one person and its affiliates other than its general partner and its affiliates.
Upon the voluntary withdrawal of ETP’s general partner, the holders of a majority of ETP’s outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect
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a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, ETP will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of its outstanding units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue ETP’s business and to appoint a successor general partner.
ETP’s general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of ETP’s outstanding units, including units held by its general partner and its affiliates, and ETP receives an opinion of counsel regarding limited liability and tax matters. In addition, if ETP’s general partner is removed as ETP’s general partner under circumstances where cause does not exist, ETP’s general partner will have the right to receive cash in exchange for its partnership interest as a general partner in ETP, its partnership interest as the general partner of any member of the Energy Transfer partnership group and its incentive distribution rights. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s general partner. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of ETP’s outstanding common units, including those held by its general partner and its affiliates.
While ETP’s partnership agreement limits the ability of ETP’s general partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of ETP’s general partner. In addition, ETP’s partnership agreement expressly permits the sale, in whole or in part, of the ownership of ETP’s general partner. ETP’s general partner may also transfer, in whole or in part, the common units it owns.
Transfer of General Partner Interests
Except for a transfer by ETP’s general partner of all, but not less than all, of its general partner interest in ETP and its operating partnership to:
| (a) | an affiliate of the general partner; or |
| (b) | another person in connection with the merger or consolidation of the general partner with or into another person or the transfer by such general partner of all or substantially all of its assets to another person; |
the general partner may not transfer all or any part of its general partner interest in ETP or its operating partnership to another person prior to June 30, 2006, without the approval of the holders of at least a majority of the outstanding common units (excluding common units held by the general partner and its affiliates); provided that, in each case, such transferee assumes the rights and duties of the general partner to whose interest such transferee has succeeded, agrees to be bound by the provisions of the partnership agreement, furnishes an opinion of counsel regarding limited liability and tax matters and agrees to acquire all (or the appropriate portion thereof, as applicable) of the general partner’s interest in each other member of ETP’s partnership group and agrees to be bound by the provisions of the operating partnership’s partnership agreement. At any time, the members of the general partner may sell or transfer all or part of their interest in the general partner to an affiliate or a third party without the approval of the unitholders.
Change of Management Provisions
ETP’s partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove ETP’s general partner or otherwise change management:
| • | any units held by a person that owns 20% or more of any class of ETP’s units then outstanding, other than its general partner and its affiliates, cannot be voted on any matter; and |
| • | the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about ETP’s operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. |
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If at any time less than 20% of the outstanding common units of any class are held by persons other than ETP’s general partner and its affiliates, its general partner will have the right to acquire all, but not less than all, of those common units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. ETP’s general partner may assign this purchase right to any of its affiliates or ETP.
ETP’s partnership agreement requires it to reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on ETP’s behalf and all other expenses allocable to ETP or otherwise reasonably incurred by its general partner in connection with operating ETP’s business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for ETP or for its general partner in the discharge of its duties to ETP. ETP’s general partner is entitled to determine the expenses that are allocable to ETP in any reasonable manner in its sole discretion.
Under its partnership agreement, in most circumstances, ETP will indemnify ETP’s general partner, its general partner’s affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to ETP’s best interest. Any indemnification under these provisions will only be out of ETP’s assets. ETP’s general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to ETP to enable ETP to effectuate any indemnification. ETP is authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under its partnership agreement.
Under its partnership agreement, ETP has agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by its general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. ETP is obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.
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UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus, affiliates of our general partner, will hold approximately 100,560,000 of our common units on a fully diluted basis, representing approximately 86.6% of our outstanding common units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
| • | 1% of the total number of the securities outstanding; or |
| • | the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. |
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements, and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his units for at least two years, would be entitled to sell units under Rule 144 without regard to the current public information requirements, volume limitations, manner of sale provisions, and notice requirements of Rule 144.
The partnership agreement provides that we may issue an unlimited number of partnership securities without a vote of the unitholders. Such units may be issued on the terms and conditions established by our general partner. Any issuance of additional units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to, and market price of, units then outstanding. Please read “Description of Our Partnership Agreement—Issuance of Additional Securities.”
Under the partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.
We, the officers and directors of our general partner, our principal unitholders and participants in our directed unit program who are affiliates of us have agreed not to sell any units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.
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This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., tax counsel to the general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy Transfer Equity.
The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of units.
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election”).
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with
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respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the processing, transportation and marketing of crude oil, natural gas and products thereof, including the retail and wholesale marketing of propane, certain hedging activities and the transportation of propane and natural gas liquids and our allocable share of such income from ETP. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Moreover, no ruling has been or will be sought from the IRS and the IRS has made no determination as to ETP’s status for federal income tax purposes or whether its operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership.
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:
| • | Neither we, nor ETP, will elect to be treated as a corporation; and |
| • | For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code. |
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. Moreover, if ETP were taxable as a corporation in any given year, our share of ETP’s items of income, gain, loss and deduction would not be passed through to us, and ETP would pay tax on its income at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation of either us or ETP as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we and ETP will be classified as a partnership for federal income tax purposes.
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Unitholders who have become limited partners of Energy Transfer Equity will be treated as partners of Energy Transfer Equity for federal income tax purposes. Also:
| • | assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners; and |
| • | unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of Energy Transfer Equity for federal income tax purposes. As there is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units. |
A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”
Income, gains, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Energy Transfer Equity for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the units, taxable in accordance with the rules described under “—Disposition of Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”
A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return
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for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.
Ratio of Taxable Income to Distributions. We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2008, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2008, the ratio of allocable taxable income to cash distributions to the unitholders will increase. Moreover, if ETP is successful in increasing distributable cash flow over time, our income allocations from incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will further increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to distributions could be higher or lower, and any differences could be material and could materially affect the value of the units.
Basis of Units. A unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Units—Recognition of Gain or Loss.”
Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally
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corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.
A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
| • | interest on indebtedness properly allocable to property held for investment; |
| • | our interest expense attributed to portfolio income; and |
| • | the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. |
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
Entity Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.
Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of this offering, referred to in this discussion
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as “Contributed Property.” The effect of these allocations to a unitholder purchasing units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
| • | his relative contributions to us; |
| • | the interests of all the partners in profits and losses; |
| • | the interest of all the partners in cash flow; and |
| • | the rights of all the partners to distributions of capital upon liquidation. |
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
| • | any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder; |
| • | any cash distributions received by the unitholder as to those units would be fully taxable; and |
| • | all of these distributions would appear to be ordinary income. |
Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”
Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
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Tax Rates. In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.
Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “—Uniformity of Units.”
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.”
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets or the tangible
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assets owned by ETP to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”
Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The tax basis of our assets owned by us at the time of this offering will be greater to the extent such assets have been recently acquired. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by the unitholders immediately prior to this offering. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
If we or ETP dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own or ETP owns will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”
The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
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Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own or ETP owns. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
| • | a short sale; |
| • | an offsetting notional principal contract; or |
| • | a futures or forward contract with respect to the partnership interest or substantially identical property. |
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical
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property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of penalties.
Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”
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We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Units—Recognition of Gain or Loss.”
Tax-Exempt Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt organizations, regulated investment companies, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income. However, recent legislation also includes net income derived from the ownership of an interest in a “qualified publicly traded partnership” as qualified income to a regulated investment company. We expect that we will meet the definition of a qualified publicly traded partnership and will, therefore, be considered a qualifying income source for mutual funds. However, this legislation is only effective for taxable years of mutual funds beginning after October 22, 2004.
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
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In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names LE GP, LLC as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
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Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:
| • | the name, address and taxpayer identification number of the beneficial owner and the nominee; |
| • | whether the beneficial owner is: |
| (1) | a person that is not a United States person; |
| (2) | a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or |
| (3) | a tax-exempt entity; |
| • | the amount and description of units held, acquired or transferred for the beneficial owner; and |
| • | specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales. |
Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
| (1) | for which there is, or was, “substantial authority,” or |
| (2) | as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return. |
If any item of income, gain, loss or deduction included in the distributive shares of unitholders for a given year might result in that kind of an “understatement” of income relating to such a transaction for which no “substantial authority” exists, we will disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for penalties. More stringent rules would apply to an understatement of tax resulting from an ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter.
A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.
Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a
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reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures” above.
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:
| • | accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-related Penalties;” |
| • | for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and |
| • | in the case of a listed transaction, an extended statute of limitations. |
We do not expect to engage in any reportable transactions.
State, Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we or ETP do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many other jurisdictions in which we may do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.
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INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS
An investment in our units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
| • | whether the investment is prudent under Section 404(a)(l)(B) of ERISA; |
| • | whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and |
| • | whether the investment will result in recognition of unrelated business taxable income (please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors”) by the plan and, if so, the potential after-tax investment return. |
In addition, the person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our units is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan. Therefore, a fiduciary of an employee benefit plan or an IRA accountholder that is considering an investment in our units should consider whether the entity’s purchase or ownership of such units would or could result in the occurrence of such a prohibited transaction.
In addition to considering whether the purchase of units is or could result in a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including fiduciary standard and its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:
| • | the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws; |
| • | the entity is an “operating company;” i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or |
| • | there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans. |
Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first bullet point above.
Plan fiduciaries contemplating a purchase of units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.
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We are offering the common units described in this prospectus through the underwriters named below. UBS Securities LLC, Wachovia Capital Markets, LLC, Credit Suisse First Boston LLC, A.G. Edwards & Sons, Inc., RBC Capital Markets Corporation, Oppenheimer & Co. Inc., Raymond James & Associates, Inc. and Stephens Inc. are the representatives of the underwriters. UBS Securities LLC, Wachovia Capital Markets, LLC and Credit Suisse First Boston LLC are the book-running managers of this offering. We have entered into an underwriting agreement with the underwriters. Subject to the terms and conditions of the underwriting agreement, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table.
| Underwriter |
Number of Units | |
| UBS Securities LLC |
||
| Wachovia Capital Markets, LLC |
||
| Credit Suisse First Boston LLC |
||
| A.G. Edwards & Sons, Inc. |
||
| RBC Capital Markets Corporation |
||
| Oppenheimer & Co. Inc. |
||
| Raymond James & Associates, Inc. |
||
| Stephens Inc. |
||
| Total |
||
The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by underwriters’ over-allotment option described below.
Our common units are being offered subject to a number of conditions, including:
| • | receipt and acceptance of our common units by the underwriters; and |
| • | the underwriters’ right to reject orders in whole or in part. |
We have been advised by the representatives that the underwriters intend to make a market in our common units but they are not obligated to do so and may discontinue making a market at any time without notice.
In connection with this offering, certain of the underwriters or securities dealers may distribute prospectuses electronically.
We have granted the underwriters an option to buy up to an aggregate of 2,250,000 additional common units. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above. If the underwriters exercise all or any portion of their over-allotment option, we will use all of the net proceeds from the sale of our common units sold pursuant to the exercise of that option to fund the redemption of an equal number of common units from our current equity owners.
Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $ per unit from the initial public offering price. Any of these securities dealers may resell common units purchased from the underwriters to other brokers or dealers at a discount of up to $ per unit from the initial public offering price. If all of the common units are not sold at the initial offering price, the representatives may change the offering price and the other selling terms. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein and, as a result, will thereafter bear any risk associated with changing the offering
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price to the public or other selling terms. The representatives of the underwriters have informed us that they do not expect to sell more than an aggregate of 300,000 common units to accounts over which such representatives exercise discretionary authority.
The following table shows the per unit and total underwriting discounts and commissions we will pay underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 2,250,000 common units.
| No Exercise |
Full Exercise | |||||
| Per unit |
$ | $ | ||||
| Total |
$ | $ | ||||
In addition, the underwriters have agreed to reimburse us for $750,000.00 of our expenses incurred in connection with this offering.
No Sales of Similar Securities
We, our executive officers and directors and substantially all of our existing common unitholders have entered into lock-up agreements with the underwriters. Under these agreements, subject to certain exceptions, we and each of these individuals and entities may not, without the prior written approval of UBS Securities LLC, Wachovia Capital Markets, LLC and Credit Suisse First Boston LLC offer, sell, contract to sell or otherwise dispose of, directly or indirectly, or hedge our common units or securities convertible into or exchangeable or exercisable for our common units. These restrictions will be in effect for a period of 180 days after the date of this prospectus. At any time and without public notice, UBS Securities LLC, Wachovia Capital Markets, LLC and Credit Suisse First Boston LLC may, in their collective discretion, release some or all of the securities from these lock-up agreements.
The 180-day restricted period described in the preceding paragraph will be extended if:
| • | during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or |
| • | prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period. |
In these situations, the restrictions in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.
We have agreed to indemnify the underwriters against certain liabilities, including certain liabilities under the Securities Act. If we are unable to provide this indemnification, we have agreed to contribute to payments the underwriters may be required to make in respect of those liabilities.
New York Stock Exchange Listing
We intend to list our common units on the New York Stock Exchange under the symbol “ETE.”
Price Stabilizations, Short Positions
In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units, including:
| • | stabilizing transactions; |
| • | short sales; |
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| • | purchases to cover positions created by short sales; |
| • | imposition of penalty bids; and |
| • | syndicate covering transactions. |
Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involve the sale by the underwriters of a greater number of common units than they are required to purchase in this offering and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered short sales,” which are short positions in an amount not greater than the underwriters’ over-allotment option referred to above, or may be “naked short sales,” which are short positions in excess of that amount.
The underwriters may close out any covered short position by either exercising their over-allotment option, in whole or in part, or by purchasing units in the open market. In making this determination, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through the over-allotment option.
Naked short sales are in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market that could adversely affect investors who purchased in this offering.
The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.
As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.
Determination of Offering Price
Prior to this offering, there was no public market for our common units. The initial public offering price will be determined by negotiation by us and the representatives of the underwriters. The principal factors to be considered in determining the initial public offering price include:
| • | the information set forth in this prospectus and otherwise available to the representatives; |
| • | our history and prospects and the history of and prospects for the industry in which we compete; |
| • | our past and present financial performance and an assessment of our management; |
| • | the prospects for future increases in the amount of cash distributed by ETP to us and, in turn, by us to our unitholders; |
| • | the general condition of the securities markets at the time of this offering; |
| • | the recent market prices of, and demand for, publicly traded common units of comparable master limited partnerships; and |
| • | other factors deemed relevant by the underwriters and us. |
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At our request, certain of the underwriters have reserved up to 1,500,000 of our common units (less than 10% of the aggregate common units being offered by this prospectus assuming full exercise of the over-allotment option) for sale at the initial public offering price to officers, directors, employees and certain other persons associated with us. The sales will be made by UBS Financial Services, Inc., a selected dealer affiliated with UBS Securities LLC, through a directed unit program. The minimum investment amount for participation in the program is $2,500.00. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of common units available to the general public. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.
Any director, officer or employee purchasing in excess of $100,000.00 worth of reserved common units will be prohibited from offering, selling, contracting to sell or otherwise disposing of the common units for a period of 180 days after the date of this prospectus.
An affiliate of Wachovia Capital Markets, LLC is a lender under our $600 million senior secured term loan facility and will receive a portion of the net proceeds from this offering when we repay approximately $240 million of indebtedness under that facility. In addition, the underwriters and their affiliates have, from time to time, and may in the future perform, various investment banking services for us and our affiliates, for which they received or will receive customary fees and expenses. Finally, K. Rick Turner, a principal of Stephens, Inc., is a director of our general partner.
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The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.
The consolidated financial statements at August 31, 2004 and 2003, the year ended August 31, 2004 and the eleven-month period ended August 31, 2003 of Energy Transfer Equity L.P. and the balance sheet of LE GP, LLC at August 31, 2004 included in this prospectus have been audited by Grant Thornton LLP, an independent registered public accounting firm, as indicated in their reports with respect thereto and are included in reliance upon the authority of said firm as experts in accounting and auditing.
The consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and for the periods ended September 30, 2002 and December 31, 2001; and the consolidated financial statements of Oasis Pipe Line Company as of December 27, 2002 and the period then ended, included in this prospectus have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon, and are included herein in reliance upon such reports given on the authority of such firm as experts in accounting and auditing. The audit report covering the consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002, and for the periods ended September 30, 2002 and December 31, 2001 refers to a change in accounting for goodwill and other intangible assets.
The consolidated financial statements of Heritage Propane Partners, L.P., as of August 31, 2003 and for the period ended January 19, 2004 and for the years ended August 31, 2003 and 2002; and the financial statements of Bi-State Propane as of August 31, 2002 and for the year ended August 31, 2002, included in this prospectus have been audited by Grant Thornton LLP, independent registered public accounting firm, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing. The audit report covering the consolidated financial statements of Heritage Propane Partners, L.P. refers to a change in accounting for stock-based compensation.
The financial statements of TXU Fuel Company as of December 31, 2003 and 2002 and for the years then ended included in this prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein, which report expresses an unqualified opinion and includes an explanatory paragraph referring to the adoption of Statement of Financial Accounting Standards No. 143, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
The financial statements of HPL Consolidation LP as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, included in this prospectus have been audited by Deloitte & Touche LLP, independent registered public accounting firm, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
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WHERE YOU CAN FIND MORE INFORMATION
We have filed with the Commission a registration statement on Form S-1 regarding the units offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the units offered by this prospectus, you should review the full registration statement, including its exhibits and schedules, filed under the Securities Act of 1933. The registration statement of which this prospectus constitutes a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the Commission at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the Commission at prescribed rates by writing to the public reference room maintained by the Commission at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the Commission at 1-800-SEC-0330. The Commission maintains a website on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded at no cost from the Commission’s web site. We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.
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F-1
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Index to Financial Statements
F-2
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F-3
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Following are Energy Transfer Equity, L.P.’s (“ETE”) unaudited pro forma consolidated statements of operations for the nine months ended May 31, 2005 and the year ended August 31, 2004, and the unaudited pro forma consolidated balance sheet as of May 31, 2005.
The unaudited pro forma consolidated financial statements give pro forma effect to the following transactions:
| • | On January 20, 2004, Heritage Propane Partners, L.P. (“Heritage”) and ETE completed the series of transactions whereby ETE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries (“ETC OLP”), to Heritage in exchange for cash of $300 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by ETE relating to the ETC OLP business prior to closing, $433.9 million of Heritage common and class D units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. |
In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to ETE and an affiliate of ETE contributed an office building to ETC OLP. ETE also received 3,742,515 special units as consideration for the project it had in progress to construct the Bossier Pipeline. The special units converted to common units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the special units to common units was approved by ETP’s Unitholders at a special meeting held on June 23, 2004.
Simultaneously with the Energy Transfer Transactions, ETE obtained control of Heritage by acquiring all of the interest in Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of Heritage, and ETP GP’s general partner, Energy Transfer Partners, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, ETP GP contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (“HOLP”) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from ETP GP for $100 million.
Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325 million from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9.2 million common units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes. Subsequent to the Energy Transfer Transactions, the combined entity was renamed Energy Transfer Partners, L.P. (“ETP”).
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETE was the acquiror for accounting purposes. The assets and liabilities of Heritage were recorded at fair value to the extent acquired in accordance with EITF 90-13, Accounting for Simultaneous Common Control Mergers. ETE, in accordance with EITF 90-13 and SFAS 141, recorded a gain of approximately $395.5 million as a result of the Energy Transfer Transactions. ETE accounted for the transaction as a partial sale of ETC OLP and a partial acquisition of Heritage, and recognized the gain to the extent ETC OLP was sold and stepped up the assets of ETC OLP to the extent ETC OLP was acquired by the minority shareholders.
| • | On June 1, 2004, ETP acquired all of the midstream natural gas assets (“ET Fuel System”) of TXU Fuel Company for approximately $500 million in an all cash transaction. This acquisition and the |
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Index to Financial Statements
| related financings are referred to as the “ET Fuel System Acquisition.” The ET Fuel System Acquisition was accounted for by ETP using the purchase method in accordance with SFAS 141. |
| • | In January 2005, ETP acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”). Under the terms of the transaction, ETC OLP acquired the 1% general partner interest and a 97% limited partner interest in HPL Consolidation LP for approximately $825 million subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350 million of ETP Common Units. In addition, working inventory of natural gas stored in the Bammel facilities was acquired and financed through a short term borrowing of $200 million by ETE, which was repaid on April 14, 2005. The total purchase price of approximately $1.4 million which included approximately $1.0 million of cash paid, net of cash acquired and liabilities assumed of $0.4 million including $0.8 million in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. This acquisition and the related financings are referred to as the “HPL Acquisition”. |
| • | On June 16, 2005, ETE borrowed $600 million from financial institutions for a term of three years. This term loan facility bears interest at an initial rate of LIBOR plus 3%, subject to adjustment based upon a ratio of total debt to EBITDA. On the date of the loan, the interest rate on the note was approximately 6.50% and is subject to change as interest rates fluctuate. Approximately $6.7 million of initial finance fees and related expenses were deferred and will be amortized over the life of the note. The net proceeds were used to pay a distribution to ETE’s equity owners, pay related costs and expenses, and for general partnership purposes. |
| • | In September 2004, ETE sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, this group purchased 1.64 million ETP Common Units for $52.4 million and ETE sold a 5% limited partner interest to this group in exchange for its contribution of 1,638,692 Common Units of ETP, its 4.9995% limited partner interest in ETP GP and its 5% member interest of ETP LLC (the “ETP GP Transactions”). |
| • | On , 2005 ETP GP amended its partnership agreement to recharacterize its limited partner interest into a 100% class A limited partner interest and a 100% class B limited partner interest. Energy Transfer Investments, LP, (“ETI”), an entity which is outside this offering and is owned by ETE’s existing members, was then issued a 50% class B limited partner interest (the “class B Transaction”). The class B limited partnership interests constitutes a profits interest in ETP GP and will only receive allocations of income, gain, loss deduction and credit and their pro rata share of cash distributions, from ETP GP attributable to the ownership of ETP’s incentive distribution rights. The class A limited partner interests are entitled to receive cash distributions related to the 2.0% general partner interest owned by ETP GP in ETP and any terminal distributions. |
| • | On July 26, 2005, ETP completed the sale of 3.0 million Common Units in a private sale to an institutional investor. The common units were issued pursuant to ETP’s effective shelf registration statement and the proceeds of $105.6 million were used by ETP to retire a portion of the outstanding indebtedness on its revolving credit facility and to fund ETP’s recently announced capital expansion projects. |
| • | The public offering proposed in this prospectus is estimated to raise approximately $266.3 million in net proceeds after underwriting fees and expenses related to this offering of approximately $3 million and has been included in cash. ETE plans to use the net proceeds from this offering to repay approximately $240 million of indebtedness outstanding under its new credit facility that was put in place in June 2005. Remaining proceeds for this offering will be used for general partnership purposes and to partially fund the acquisition of additional 3.64 million common units of ETP. |
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Index to Financial Statements
The following unaudited pro forma consolidated financial statements include the following:
| • | the unaudited pro forma balance sheet of ETE, which gives the pro forma effects to $600 million debt transaction, the ETP GP Transactions, the class B Transaction, the sale of 3.0 million ETP Common Units, and the proceeds of this offering as if the transactions occurred on May 31, 2005; |
| • | The unaudited pro forma statement of operations of ETE for the twelve months ended August 31, 2004, which gives pro forma effect to the Energy Transfer Transactions, the ET Fuel System Acquisitions, the HPL Acquisition, the $600 million debt transaction, the ETP GP Transactions, the class B Transaction, the sale of 3.0 million ETP Common Units, and the proceeds of this offering as if such transactions occurred on September 1, 2003; and |
| • | the unaudited pro forma statement of operations of ETE for the nine months ended May 31, 2005, which gives pro forma effect to the HPL Acquisition, the $600 million debt transaction, the ETP GP Transaction, the class B Transaction, the sale of 3.0 million ETP Common Units, and the proceeds of this offering as if such transactions occurred on September 1, 2004. |
The unaudited pro forma condensed consolidated financial statements are provided for informational purposes only and should be read in conjunction with the audited or unaudited consolidated financial statements of the respective entities, all included in this registration statement.
The following unaudited pro forma consolidated financial statements are based on certain assumptions and does not purport to be indicative of the results which actually would have been achieved if the transactions described therein had been consummated on the dates indicated. Moreover, they do not project ETE’s financial position or results of operations for any future date or period. In addition, the unaudited pro forma consolidated statement of operations for the year ended August 31, 2004, exclude discontinued operations related to April 2005 sale by ETP of ETC Oklahoma Pipeline, Ltd.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS
For the Year Ended August 31, 2004
(In thousands)
| Energy Transfer Equity |
Heritage |
Heritage Holdings |
ET Fuel System |
HPL System |
Adjustments for Acquisitions |
Pro Forma for Acquisitions |
||||||||||||||||||||||||
| REVENUES: |
||||||||||||||||||||||||||||||
| Midstream, transportation and storage |
$ | 1,966,803 | $ | — | $ | — | $ | 40,834 | $ | 3,691,879 | $ | — | $ | 5,699,516 | ||||||||||||||||
| Propane |
342,523 | 242,424 | — | — | — | — | 584,947 | |||||||||||||||||||||||
| Other |
37,631 | 27,928 | — | — | — | — | 65,559 | |||||||||||||||||||||||
| Total revenues |
2,346,957 | 270,352 | — | 40,834 | 3,691,879 | — | 6,350,022 | |||||||||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||||||||
| Cost of products sold |
1,981,424 | 148,329 | — | — | 3,541,243 | — | 5,670,996 | |||||||||||||||||||||||
| Operating expenses |
147,374 | 60,735 | — | 7,714 | 72,328 | — | 288,151 | |||||||||||||||||||||||
| Selling, general and administrative |
31,111 | 10,100 | — | 2,109 | 22,425 | (36 | ) | (h) | 65,709 | |||||||||||||||||||||
| Depreciation and amortization |
56,242 | 15,389 | — | 3,986 | 12,037 | 543 | (f) | 105,676 | ||||||||||||||||||||||
| 487 | (g) | |||||||||||||||||||||||||||||
| 25 | (h) | |||||||||||||||||||||||||||||
| 2,761 | (j) | |||||||||||||||||||||||||||||
| 8,747 | (a) | |||||||||||||||||||||||||||||
| 5,459 | (i) | |||||||||||||||||||||||||||||
| Asset impairments |
— | — | — | — | 300,000 | (300,000 | ) | (k) | — | |||||||||||||||||||||
| Total costs and expenses |
2,216,151 | 234,553 | — | 13,809 | 3,948,033 | (282,014 | ) | 6,130,532 | ||||||||||||||||||||||
| OPERATING INCOME (LOSS) |
130,806 | 35,799 | — | 27,025 | (256,154 | ) | 282,014 | 219,490 | ||||||||||||||||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||||||||||||||||||||
| Interest expense |
(41,217 | ) | (12,754 | ) | — | (884 | ) | (40 | ) | (17,716 | ) | (l) | (135,309 | ) | ||||||||||||||||
| (21,465 | ) | (b) | ||||||||||||||||||||||||||||
| (41,233 | ) | (v) | ||||||||||||||||||||||||||||
| Equity in earnings of affiliates |
363 | 496 | 5,218 | — | (670 | ) | (5,218 | ) | (m) | 189 | ||||||||||||||||||||
| Loss on disposal of assets |
(1,006 | ) | (240 | ) | — | — | — | 100 | (n) | (1,146 | ) | |||||||||||||||||||
| Interest income and other |
516 | (66 | ) | 346 | (138 | ) | 3,050 | (346 | ) | (o) | 3,362 | |||||||||||||||||||
| Gain on Heritage Transaction |
395,253 | — | — | — | — | (395,253 | ) | (q) | — | |||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND INCOME TAXES |
484,715 | 23,235 | 5,564 | 26,003 | (253,814 | ) | (199,117 | ) | 86,586 | |||||||||||||||||||||
| Minority interests |
(35,164 | ) | (572 | ) | — | — | — | 230 | (p) | (79,626 | ) | |||||||||||||||||||
| (83 | ) | (c) | ||||||||||||||||||||||||||||
| 43,665 | (r) | |||||||||||||||||||||||||||||
| (3,071 | ) | (u) | ||||||||||||||||||||||||||||
| 2,070 | (s) | |||||||||||||||||||||||||||||
| (3,623 | ) | (x) | ||||||||||||||||||||||||||||
| 4,252 | (i) | |||||||||||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
449,551 | 22,663 | 5,564 | 26,003 | (253,814 | ) | 243,007 | 6,960 | ||||||||||||||||||||||
| Income tax (expense) benefit |
(2,792 | ) | (20 | ) | (2,245 | ) | (9,881 | ) | 66,428 | (56,547) | (d) | (5,273 | ) | |||||||||||||||||
| 1,207 | (i) | |||||||||||||||||||||||||||||
| — | — | — | — | — | (1,423 | ) | (e) | — | ||||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS |
446,759 | $ | 22,643 | $ | 3,319 | $ | 16,122 | $ | (187,386 | ) | $ | (299,770 | ) | $ | 1,687 | |||||||||||||||
| GENERAL PARTNER’S INTEREST IN INCOME FROM CONTINUING OPERATIONS |
4,401 | |||||||||||||||||||||||||||||
| LIMITED PARTNERS’ INTEREST IN INCOME FROM CONTINUING OPERATIONS |
$ | 442,358 | ||||||||||||||||||||||||||||
| BASIC INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 2.47 | ||||||||||||||||||||||||||||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
179,162,636 | |||||||||||||||||||||||||||||
| DILUTED INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 1.83 | ||||||||||||||||||||||||||||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
242,479,820 | |||||||||||||||||||||||||||||
F-7
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
STATEMENT OF OPERATIONS—(Continued)
For the Year Ended August 31, 2004
(In thousands)
| Pro Forma for Acquisitions |
Offering Adjustments |
Pro Forma as Adjusted |
|||||||||||
| REVENUES: |
|||||||||||||
| Midstream, transportation and storage |
$ | 5,699,516 | $ | — | $ | 5,699,516 | |||||||
| Propane |
584,947 | — | 584,947 | ||||||||||
| Other |
65,559 | — | 65,559 | ||||||||||
| Total revenues |
6,350,022 | — | 6,350,022 | ||||||||||
| COSTS AND EXPENSES: |
|||||||||||||
| Cost of products sold |
5,670,996 | — | 5,670,996 | ||||||||||
| Operating expenses |
288,151 | — | 288,151 | ||||||||||
| Selling, general and administrative |
65,709 | — | 65,709 | ||||||||||
| Depreciation and amortization |
105,676 | — | 105,676 | ||||||||||
| Asset impairments |
— | — | — | ||||||||||
| Total costs and expenses |
6,130,532 | — | 6,130,532 | ||||||||||
| OPERATING INCOME |
219,490 | — | 219,490 | ||||||||||
| OTHER INCOME (EXPENSE): |
|||||||||||||
| Interest expense |
(135,309 | ) | 15,600 | (z) | (119,709 | ) | |||||||
| Equity in earnings of affiliates |
189 | — | 189 | ||||||||||
| Loss on disposal of assets |
(1,146 | ) | — | (1,146 | ) | ||||||||
| Interest income and other |
3,362 | — | 3,362 | ||||||||||
| Gain on Heritage Transaction |
— | — | — | ||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND INCOME TAXES |
86,586 | 15,600 | 102,186 | ||||||||||
| Minority interests |
(79,626 | ) | 3,504 | (bb) | (76,122 | ) | |||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
6,960 | 19,104 | 26,064 | ||||||||||
| Income tax (expense) |
(5,273 | ) | — | (5,273 | ) | ||||||||
| INCOME FROM CONTINUING OPERATIONS |
$ | 1,687 | $ | 19,104 | 20,791 | ||||||||
| GENERAL PARTNER’S INTEREST IN INCOME FROM CONTINUING OPERATIONS |
113 | ||||||||||||
| LIMITED PARTNERS’ INTEREST IN INCOME FROM CONTINUING OPERATIONS |
$ | 20,678 | |||||||||||
| BASIC INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 0.18 | |||||||||||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
115,560,061 | ||||||||||||
| DILUTED INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 0.81 | |||||||||||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
115,560,061 | ||||||||||||
F-8
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
As of May 31, 2005
(In thousands)
| Energy Transfer Equity |
Adjustments for debt transaction |
Pro Forma |
Pro Forma Adjustments |
Pro forma as Adjusted | |||||||||||||||||
| ASSETS: | |||||||||||||||||||||
| CURRENT ASSETS: |
|||||||||||||||||||||
| Cash and cash equivalents |
$ | 21,607 | $ | 52,399 | (s) | $ | 121,906 | $ | 266,325 | (y) | $ | 267,946 | |||||||||
| 105,600 | (t) | (240,000 | ) | (z) | |||||||||||||||||
| (60,000 | ) | (t) | |||||||||||||||||||
| 593,900 | (v) | 119,715 | (aa) | ||||||||||||||||||
| (591,000 | ) | (w) | |||||||||||||||||||
| (600 | ) | (v) | |||||||||||||||||||
| Marketable securities |
2,658 | 2,658 | 2,658 | ||||||||||||||||||
| Accounts receivable, net of allowance for doubtful accounts |
729,261 | 729,261 | 729,261 | ||||||||||||||||||
| Accounts receivable from related companies |
665 | 665 | 665 | ||||||||||||||||||
| Inventories |
261,413 | 261,413 | 261,413 | ||||||||||||||||||
| Deposits paid to vendors |
46,441 | 46,441 | 46,441 | ||||||||||||||||||
| Exchanges receivable |
19,819 | 19,819 | 19,819 | ||||||||||||||||||
| Price risk management assets |
36,307 | 36,307 | 36,307 | ||||||||||||||||||
| Prepaid expenses and other |
59,774 | 59,774 | 59,774 | ||||||||||||||||||
| Total current assets |
1,177,945 | 100,299 | 1,278,244 | 146,040 | 1,424,284 | ||||||||||||||||
| PROPERTY, PLANT AND EQUIPMENT, net |
2,824,372 | 2,824,372 | 2,824,372 | ||||||||||||||||||
| LONG-TERM PRICE RISK MANAGEMENT ASSETS |
18,824 | 18,824 | 18,824 | ||||||||||||||||||
| INVESTMENT IN AFFILIATES |
40,857 | 40,857 | 40,857 | ||||||||||||||||||
| GOODWILL |
351,320 | 351,320 | 351,320 | ||||||||||||||||||
| INTANGIBLES AND OTHER ASSETS, net |
109,037 | 6,700 | (v) | 115,737 | 115,737 | ||||||||||||||||
| Total assets |
$ | 4,522,355 | $ | 106,999 | $ | 4,629,354 | $ | 146,040 | $ | 4,775,394 | |||||||||||
| LIABILITIES AND PARTNERS’ CAPITAL | |||||||||||||||||||||
| CURRENT LIABILITIES: |
|||||||||||||||||||||
| Accounts payable |
$ | 773,904 | $ | — | $ | 773,904 | $ | — | $ | 773,904 | |||||||||||
| Accounts payable to related companies |
3,572 | 3,572 | 3,572 | ||||||||||||||||||
| Exchanges payable |
20,612 | 20,612 | 20,612 | ||||||||||||||||||
| Customer deposits |
24,978 | 24,978 | 24,978 | ||||||||||||||||||
| Accrued and other current liabilities |
119,316 | 119,316 | 119,316 | ||||||||||||||||||
| Price risk management liabilities |
38,736 | 38,736 | 38,736 | ||||||||||||||||||
| Income taxes payable |
1,075 | 1,075 | 1,075 | ||||||||||||||||||
| Current maturities of long-term debt |
33,425 | 33,425 | 33,425 | ||||||||||||||||||
| Total current liabilities |
1,015,618 | — | 1,015,618 | — | 1,015,618 | ||||||||||||||||
F-9
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
As of May 31, 2005
(In thousands)
| Energy Transfer Equity |
Adjustments for debt transaction |
Pro Forma |
Pro Forma Adjustments |
Pro forma as Adjusted | ||||||||||||||||||
| LONG-TERM DEBT, net of discount, less current maturities |
1,570,155 | (60,000 | ) | (t) | 2,110,155 | (240,000 | ) | (z) | 1,870,155 | |||||||||||||
| 600,000 | (v) | |||||||||||||||||||||
| LONG-TERM PRICE RISK MANAGEMENT LIABILITIES |
18,861 | 18,861 | 18,861 | |||||||||||||||||||
| OTHER NONCURRENT LIABILITIES |
16,660 | 16,660 | 16,660 | |||||||||||||||||||
| DEFERRED TAXES |
219,224 | 219,224 | 219,224 | |||||||||||||||||||
| MINORITY INTERESTS |
1,257,862 | 4,455 | (x) | 1,364,432 | 1,364,432 | |||||||||||||||||
| 52,399 | (s) | |||||||||||||||||||||
| (55,884 | ) | (s) | ||||||||||||||||||||
| 105,600 | (t) | |||||||||||||||||||||
| 4,098,380 | 646,570 | 4,744,950 | (240,000 | ) | 4,504,950 | |||||||||||||||||
| COMMITMENTS AND CONTINGENCIES |
||||||||||||||||||||||
| PARTNERS’ CAPITAL: |
||||||||||||||||||||||
| Limited Partners |
413,464 | (586,780 | ) | (w) | (121,859 | ) | 266,325 | (z) | 264,181 | |||||||||||||
| 55,884 | (s) | |||||||||||||||||||||
| (4,427 | ) | (x) | 119,715 | (bb) | ||||||||||||||||||
| General Partner |
4,550 | (4,220 | ) | (w) | 302 | 302 | ||||||||||||||||
| (28 | ) | (x) | ||||||||||||||||||||
| Accumulated other comprehensive income |
5,961 | 5,961 | — | 5,961 | ||||||||||||||||||
| Total partners’ capital |
423,975 | (539,571 | ) | (115,596 | ) | 386,040 | 270,444 | |||||||||||||||
| Total liabilities and partners’ capital |
$ | 4,522,355 | $ | 106,999 | $ | 4,629,354 | $ | 146,040 | $ | 4,775,394 | ||||||||||||
F-10
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
For the Nine Months Ended May 31, 2005
(In thousands)
| Energy Transfer Equity |
HPL System |
Adjustments for Acquisitions |
ETE Pro |
Offering Adjustments |
Pro Forma as Adjusted |
||||||||||||||||||||||
| REVENUES: |
|||||||||||||||||||||||||||
| Midstream, transportation and storage |
$ | 3,673,730 | $ | 1,668,224 | $ | — | $ | 5,341,954 | $ | — | $ | 5,341,954 | |||||||||||||||
| Propane |
604,996 | — | — | 604,996 | — | 604,996 | |||||||||||||||||||||
| Other |
57,065 | — | — | 57,065 | — | 57,065 | |||||||||||||||||||||
| Total revenues |
4,335,791 | 1,668,224 | — | 6,004,015 | — | 6,004,015 | |||||||||||||||||||||
| COSTS AND EXPENSES: |
|||||||||||||||||||||||||||
| Cost of products sold |
3,756,078 | 1,582,748 | — | 5,338,826 | — | 5,338,826 | |||||||||||||||||||||
| Operating expenses |
224,122 | 27,217 | — | 251,339 | — | 251,339 | |||||||||||||||||||||
| Selling, general and administrative |
43,813 | 8,974 | — | 52,787 | — | 52,787 | |||||||||||||||||||||
| Depreciation and amortization |
76,874 | 4,953 | 3,707 | (a) | 85,534 | — | 85,534 | ||||||||||||||||||||
| Total costs and expenses |
4,100,887 | 1,623,892 | 3,707 | 5,728,486 | — | 5,728,486 | |||||||||||||||||||||
| OPERATING INCOME (LOSS) |
234,904 | 44,332 | (3,707 | ) | 275,529 | — | 275,529 | ||||||||||||||||||||
| OTHER INCOME (EXPENSE): |
|||||||||||||||||||||||||||
| Interest expense |
(66,350 | ) | (866 | ) | (14,309 | ) | (b) | (111,331 | ) | 11,700 | (z) | (99,631 | ) | ||||||||||||||
| (30,925 | ) | (v) | |||||||||||||||||||||||||
| 1,119 | (t) | ||||||||||||||||||||||||||
| Loss on extinguishment of debt |
(6,550 | ) | — | — | (6,550 | ) | — | (6,550 | ) | ||||||||||||||||||
| Equity in earnings of affiliates |
(161 | ) | (16 | ) | — | (177 | ) | — | (177 | ) | |||||||||||||||||
| Loss on disposal of assets |
(665 | ) | — | — | (665 | ) | — | (665 | ) | ||||||||||||||||||
| Interest income and other |
308 | 4,390 | — | 4,698 | — | 4,698 | |||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE MINORITY INTEREST AND INCOME TAXES |
161,486 | 47,840 | (47,822 | ) | 161,504 | 11,700 | 173,204 | ||||||||||||||||||||
| Minority interests |
(91,439 | ) | — | (562 | ) | (c) | (119,968 | ) | 5,223 | (bb) | (114,745 | ) | |||||||||||||||
| (20,132 | ) | (r) | |||||||||||||||||||||||||
| (2,461 | ) | (u) | |||||||||||||||||||||||||
| (6,409 | ) | (x) | |||||||||||||||||||||||||
| 1,035 | (s) | ||||||||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
70,047 | 47,840 | (76,351 | ) | 41,536 | 16,923 | 58,459 | ||||||||||||||||||||
| Income tax (expense) benefit |
(5,168 | ) | (15,608 | ) | 15,608 | (d) | (5,776 | ) | — | (5,776 | ) | ||||||||||||||||
| (608 | ) | (e) | |||||||||||||||||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS |
64,879 | $ | 32,232 | $ | (61,351 | ) | $ | 35,760 | $ | 16,923 | $ | 52,683 | |||||||||||||||
| GENERAL PARTNER’S INTEREST IN INCOME FROM CONTINUING OPERATIONS |
547 | 287 | |||||||||||||||||||||||||
| LIMITED PARTNERS’ INTEREST IN INCOME FROM CONTINUING OPERATIONS |
$ | 64,332 | $ | 52,396 | |||||||||||||||||||||||
| BASIC INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 0.33 | $ | 0.45 | |||||||||||||||||||||||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
194,171,059 | 115,560,061 | |||||||||||||||||||||||||
| DILUTED INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT |
$ | 0.27 | $ | 0.45 | |||||||||||||||||||||||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
242,754,055 | 115,560,061 | |||||||||||||||||||||||||
F-11
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Other Transactions
The unaudited pro forma condensed consolidated financial statements do not give any effect to any restructuring cost, potential cost savings, or other operating efficiencies that are expected to result from the transactions described herein. The unaudited pro forma consolidated financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the transactions had been consummated on the dates indicated or which may be achieved in the future. Moreover, it does not project ETE’s financial position or results of operations for any future date or period. The purchase accounting adjustments made in connection with the development of the unaudited pro forma consolidated financial statements with respect to the HPL Acquisition are preliminary and have been made solely for purposes of presenting such pro forma financial information.
The historical financial information is derived from the historical financial statements of Energy Transfer Equity, L.P., Heritage Propane Partners, L.P., Heritage Holdings, Inc., TXU Fuel Company, and HPL Consolidation LP.
The following unaudited pro forma financial statement present (i) unaudited pro forma consolidated balance sheet at May 31, 2005, giving effect to the $600 million debt transaction, the ETP GP Transactions, the class B Transaction, the sale of 30 million ETP Common Units, and the proceeds of this offering as if these transactions occurred on May 31, 2005; (ii) unaudited pro forma statement of operations for the year ended August 31, 2004, giving effect to the transactions as listed in (i) above and those described below as if they occurred on September 1, 2003; and (iii) unaudited pro forma consolidated statement of operations for the nine months ended May 31, 2005, giving effect to the transactions as listed in (i) above and those described below as if they occurred on September 1, 2004. The unaudited pro forma consolidated statement of operations for the year ended August 31, 2004 consolidates the historical results of continuing operations of ETE for the year ended August 31, 2004, the historical results of operations for Heritage and Heritage Holdings for the period from September 1, 2003 through January 19, 2004, the historical results of operations for the ET Fuel System for the period from September 1, 2003 through June 30, 2004 and of HPL for the year ended September 30, 2004 after giving effect to pro forma adjustments. The unaudited pro forma condensed consolidated statement of operations for the nine months ended May 31, 2005 consolidates the historical results of operations for ETE for the nine months ended May 31, 2005 and of HPL for the five months ended January 31, 2005, after giving effect to pro forma adjustments. Included in the results of operations of HPL for the five months ended January 31, 2005 was approximately $1.8 million related to the reduction of certain environmental and legal accrued liabilities. The reduction was accounted for as a change in estimate.
On January 20, 2004, Heritage Propane Partners, L.P. (“Heritage”) and ETE completed the series of transactions whereby ETE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries (“ETC OLP”), to Heritage in exchange for cash of $300.0 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by ETE relating to the ETC OLP business prior to closing, $433.9 million of Heritage common and class D units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions.
In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to ETE and an affiliate of ETE contributed an office building to ETC OLP. ETE also received 3,742,515 special units as consideration for the project it had in progress to construct the Bossier Pipeline. The special units converted to common units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the special units to common units was approved by ETP’s Unitholders at a special meeting held on June 23, 2004.
F-12
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Simultaneously with the Energy Transfer Transactions, ETE obtained control of Heritage by acquiring all of the interest in ETP GP, the General Partner of Heritage, and ETP GP’s general partner, Energy Transfer Partners, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, ETP GP contributed its 1.0101% General Partner interest in HOLP to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from ETP GP for $100 million.
Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325 million from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9.2 million common units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes. Subsequent to the Energy Transfer Transactions, the combined entity was renamed Energy Transfer Partners, L.P. (“ETP”).
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETE was the acquiror for accounting purposes. ETE, in accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141, recorded a gain of approximately $395.5 million as a result of the Energy Transfer Transactions. ETE accounted for the transaction as a partial sale of ETC OLP and a partial acquisition of Heritage, and recognized a gain to the extent ETC OLP was sold and stepped up the assets of ETC OLP to the extent ETC OLP was acquired by the minority shareholders.
F-13
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The excess purchase price over Heritage cost was allocated as follows (in thousands):
| Net book value of Heritage at January 20, 2004 |
$ | 239,102 | ||
| Historical goodwill at January 20, 2004 |
(170,500 | ) | ||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 267,210 | ||||
| Percent of Heritage acquired by ETC OLP |
41.5 | % | ||
| Equity interest acquired |
$ | 110,892 | ||
| Fair market value of Limited Partner Units |
668,534 | |||
| Purchase price of General Partner Interest |
30,000 | |||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 897,142 | ||||
| Percent of Heritage acquired by ETC OLP |
41.5 | % | ||
| Fair value of equity acquired |
372,314 | |||
| Net book value of equity acquired |
110,892 | |||
| Excess purchase price over Heritage cost |
$ | 261,422 | ||
The excess purchase price over Heritage cost was allocated as follows:
| Property, plant and equipment (25 year life) |
$ | 35,269 | |
| Customer lists (15 year life) |
18,926 | ||
| Trademarks |
19,251 | ||
| Goodwill |
187,976 | ||
| $ | 261,422 | ||
Goodwill was warranted in the Energy Transfer Transactions because the business enterprise value of the operations acquired exceeded the fair market value of the tangible and identifiable intangible assets acquired. ETP GP’s partner’s capital was determined based on the purchase price paid by ETE. Goodwill of $29.6 million was recorded in connection with ETE’s acquisition of ETP GP.
The gain recognized by ETE as a result of the Energy Transfer Transaction was determined as follows (in thousands):
| ETE’s historical basis in ETC OLP |
$ | (90,906 | ) | |
| Percent sold in Energy Transfer Transactions |
58.5 | % | ||
| (53,180 | ) | |||
| Fair value of Heritage equity acquired in Energy Transfer Transactions |
372,314 | |||
| Less: Consideration paid for ETP’s GP interest |
$ | (30,000 | ) | |
| Fair value of assets received in Energy Transfer Transactions |
$ | 342,314 | ||
| Gain on sale of partial sale of ETC OLP |
$ | 395,494 | ||
F-14
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE in the Energy Transfer Transactions of approximately 58.5%, determined in accordance with EITF 90-13 and SFAS 141. The step-up resulted in an approximate $504 million increase to property, plant and equipment at ETE which is being depreciated over estimated lives of 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributed to a taxable entity of ETC OLP, resulting in approximately $108.5 million of deferred taxes recorded by ETE.
On June 1, 2004, ETP acquired all of the midstream natural gas assets (“ET Fuel System”) of TXU Fuel Company for approximately $504 million in an all cash transaction. This acquisition and the related financings are referred to as the “ET Fuel System Acquisition.” The ET Fuel System Acquisition was accounted for by ETP using the purchase method in accordance with SFAS 141. The purchase price was determined as follows (in thousands):
| Cash paid |
$ | 498,571 | |
| Liabilities assumed |
11,602 | ||
| Total purchase price |
$ | 510,173 | |
The purchase price was allocated as follows (in thousands):
| Property, plant and equipment, including construction in progress |
$ | 499,846 | ||
| Goodwill |
10,327 | |||
| Exchanges payable |
(10,094 | ) | ||
| Deposits from vendors |
(750 | ) | ||
| Accrued expenses |
(758 | ) | ||
| $ | 498,571 | |||
In January 2005, ETP acquired the controlling interests in HPL from the American Electric Power Corporation (“AEP”). Under the terms of the transaction, ETC OLP acquired the 1% general partner interest and a 97% limited partner interest in HPL Consolidated LP for approximately $825,000 subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350 million of ETP Common Units. In addition, working inventory of natural gas stored in the Bammel storage facilities was acquired and financed through a short-term borrowing of $200 million by ETE, which was repaid on April 14, 2005. The total purchase price of approximately $1.4 million which included approximately $1.0 million of cash paid, net of cash acquired and liabilities assumed of $0.4 million including $0.8 million in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. This acquisition and the related financings are referred to as the “HPL Acquisition”.
The HPL Acquisition is accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS No. 141. The estimated purchase price was determined as follows (in thousands):
| Cash paid |
$ | 1,039,358 | |
| Liabilities assumed |
412,470 | ||
| Estimated acquisition costs |
800 | ||
| Estimated purchase price |
$ | 1,452,628 | |
F-15
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
For purposes of this pro forma analysis, the purchase price of the HPL transaction has been allocated using the acquisition methodology used by ETP when evaluating potential acquisitions. Initial estimates are that the purchase price may be assigned to depreciable fixed assets or amortizable, intangible assets or tangible assets as opposed to non-amortizable goodwill. Management of ETP has engaged an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from the preliminary allocation. To the extent that the final allocation will result in an allocation to goodwill, this amount would not be subject to amortization, but would be subject to an annual impairment testing and if necessary, written-down to a lower fair value should circumstances warrant. However, ETP’s management does not anticipate that the final valuation will be materially different than the preliminary allocation. The allocation to assets acquired and liabilities assumed is as follows (in thousands):
| Current assets |
$ | 566,664 | ||
| Property, plant and equipment, including construction in progress |
824,386 | |||
| Other assets |
61,578 | |||
| Current liabilities |
(362,793 | ) | ||
| Other liabilities |
(50,477 | ) | ||
| $ | 1,039,358 | |||
2. Pro Forma Adjustments (in thousands)
(a) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment having estimated useful lives ranging from 5-65 years, which occurred in the HPL Acquisition. The estimated weighted average useful life was 45 years.
(b) Reflects additional interest expense on $475 million of borrowings under ETP’s credit facility and $200 million of borrowings by ETE to finance the HPL Acquisition pro forma interest or the $200 million was reflected only for the period outstanding. The borrowings have an interest rate of 4.30% and 4.10%, respectively.
(c) Reflects a 2% minority interest adjustment related to AEP’s retained limited partnership interest in HPL.
(d) Eliminates income tax expense as the assets acquired in the ET Fuel System and HPL Acquisitions are now owned by a non-taxable limited partnership.
(e) Reflects additional income tax on Heritage Holdings, Inc.
(f) Reflects the additional depreciation related to the step-up of net book value of HOLP property, plant and equipment having an estimated average life of 25 years, which occurred in the Energy Transfer Transactions.
(g) Reflects the additional amortization related to the step-up of net book value of customer lists having lives of 15 years, which occurred in the Energy Transfer Transactions.
(h) Reflects the effect on depreciation of the contribution of the Dallas office building from ETE to ETC OLP and the reversal of rent previously expensed.
(i) Reflects the additional deprecation related to the step-up of net book value of ETC OLP’s property, plant and equipment having estimated average useful lives ranging from 5-65 years by ETE to the extent acquired by minority shareholders, which occurred in the Energy Transfer Transactions and the reversal of the deferred tax liability estimated at the same rate of 5-65 years in correspondence to the related assets.
F-16
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(j) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment having estimated useful lives ranging from 5-65 years, which occurred in the ET Fuel System Acquisition. The estimated weighted average useful life was 52.4 years.
(k) Reflects the reversal the asset impairment charge in order to properly reflect the fair value of the assets assuming the transaction occurred at September 1, 2003.
(l) Reflects additional interest expense on $325 million of borrowings to finance the Energy Transfer Transactions and $505 million of borrowings to finance the ET Fuel System Acquisition. The borrowings have an interest rate of 4.14%. Includes amortization of additional loan origination costs of $8.5 million.
(m) Reflects elimination of Heritage Holdings, Inc.’s equity in earnings of Heritage.
(n) Reflects the elimination of 41.5% of the loss on sale of assets as Heritage’s assets are recorded at fair market value.
(o) Reflects the elimination of interest income from the note receivable of $11.5 million between HHI and ETP GP, which was retained by the subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. in the Energy Transfer Transactions. The note had an interest rate of 6%.
(p) Reflects the elimination of minority interest expense for the 1.0101% general partner’s interest in HOLP contributed to Heritage for an additional 1% general partner interest in Heritage, which occurred in the Energy Transfer Transactions.
(q) Reflects the elimination of the gain recorded by ETE under EITF 90-13 on the Energy Transfer Transactions as if the transactions had occurred as of September 1, 2003 for the fiscal year ended August 31, 2004.
(r) Reflects the allocation of pro forma adjustments to net income related to the Energy Transfer Transactions, ET Fuel System Acquisition, the HPL Acquisition, and the interest expense reduction related to the debt retirement from the proceeds from the June 2005 ETP Equity Issue to minority interests.
(s) Reflects the pro forma affects of the ETP GP Transaction as if the transaction had occurred at the beginning of the periods presented. ETE’s ownership percentage in ETP increased due to the contribution of 1,638,692 ETP units contributed in the ETP GP Transaction increasing its equity pick-up of income from ETP for the fiscal year ended August 31, 2004 and the nine-months ended May 31, 2005. ETE’s ownership in ETP GP also increases from the ETP GP Transaction increasing its equity in earnings of ETP GP for the nine months ended May 31, 2005.
(t) Reflects the pro forma affects of $105.6 million of proceeds received in the July 2005 ETP Equity Issue of 3.0 million Common Units and the subsequent payment of $60 million from these proceeds to retire a portion of ETP’s outstanding indebtedness on its revolving credit facility. Pro forma interest adjustment on the retirement of the outstanding indebtedness is at an assumed rate of 5.04%.
(u) Reflects the pro forma minority interest expense adjustment related to ETE’s ownership dilution in ETP if the Energy Transfer Transactions, the HPL Acquisition, the purchase of the common units in the ETP GP Transaction, and the July 2005 ETP Equity Issue had occurred as of the beginning of the periods presented.
F-17
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(v) Reflects proceeds received in the $600 million debt transaction, net of related loan issuance costs of $6.7 million. This term loan facility matures on June 16, 2008 and bears interest at an initial rate of LIBOR plus 3%. Pro forma interest adjustment on the borrowings is at an assumed rate of 6.50%, and the related amortization of the debt issuance costs amortized on a straight-line basis over 3 years.
(w) Reflects the distribution of $591 million of the net proceeds from the $600 million debt transaction to the existing partners of ETE at their relative percentage interests.
(x) Reflects the pro forma effects of the class B Transaction in which 50% of the class B units were issued to ETI, which is outside this offering.
(y) Reflects the issuance of $269.3 million in net proceeds from this public offering and an additional $3.0 million for estimated costs related to this offering. A conversion ratio of 46.07% was determined in deriving the common units outstanding at the time of this public offering, which was based on a 3.68% yield on $81.3 million of distributable cash flow expected by ETE. The units offered to the public are units held currently by the existing limited partners of ETE, therefore the existing limited partners will experience an immediate dilution to their current ownership of ETE.
(z) Reflects the pro forma adjustment related to the $240 million debt pay down from offering proceeds and the reduction of related interest expense at an assumed rate of 6.5%.
(aa) Reflects the purchase of 3.64 ETP common units at an assumed price of $36.00 per unit. The purchase of these units is funded through $25.5 million of the remaining proceeds from this public offering after the $240 million debt pay down and the retention of $15 million of the proceeds for general partnership purposes and a $119.7 million equity contribution from the existing partners of ETE at their relative percentage interests before this public offering.
(bb) Reflects the pro forma affects of the additional income from the increased ownership percentage in ETP after the purchase of the additional 3.64 million ETP common units in conjunction with this public offering.
F-18
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Equity, L.P.
We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. and subsidiaries, as of August 31, 2004 and 2003 and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for the year ended August 31, 2004 and the eleven months ended August 31, 2003. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of August 31, 2004 and 2003 and the results of their operations and their cash flows for the year ended August 31, 2004 and the eleven months ended August 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Tulsa, Oklahoma
September 1, 2005
F-19
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
| August 31, | ||||||
| 2004 |
2003 | |||||
| ASSETS |
||||||
| CURRENT ASSETS: |
||||||
| Cash and cash equivalents |
$ | 82,852 | $ | 55,072 | ||
| Marketable securities |
2,464 | — | ||||
| Accounts receivable, net of allowance for doubtful accounts |
251,346 | 97,772 | ||||
| Accounts receivable from related companies |
35 | — | ||||
| Inventories |
53,261 | 3,884 | ||||
| Deposits paid to vendors |
3,023 | 19,053 | ||||
| Exchanges receivable |
8,640 | 643 | ||||
| Price risk management assets |
4,615 | 928 | ||||
| Prepaid expenses and other |
7,724 | 804 | ||||
| Assets held for sale |
67,908 | 9,061 | ||||
| Total current assets |
481,868 | 187,217 | ||||
| PROPERTY, PLANT AND EQUIPMENT, net |
1,915,274 | 354,309 | ||||
| PROPERTY, PLANT AND EQUIPMENT HELD FOR SALE, net |
— | 38,716 | ||||
| INVESTMENT IN AFFILIATES |
8,010 | 6,844 | ||||
| GOODWILL |
348,761 | 13,409 | ||||
| INTANGIBLES AND OTHER ASSETS, net |
111,278 | 3,645 | ||||
| Total assets |
$ | 2,865,191 | $ | 604,140 | ||
The accompanying notes are an integral part of these consolidated financial statements.
F-20
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS—(Continued)
(in thousands, except unit data)
| August 31, | ||||||
| 2004 |
2003 | |||||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||
| CURRENT LIABILITIES: |
||||||
| Working capital facility |
$ | 14,550 | $ | — | ||
| Accounts payable |
235,631 | 106,504 | ||||
| Accounts payable to related companies |
1,507 | 822 | ||||
| Exchanges payable |
12,751 | 834 | ||||
| Customer deposits |
11,378 | 11,600 | ||||
| Liabilities from discontinued operations |
20,590 | 8,910 | ||||
| Accrued and other current liabilities |
73,762 | 7,907 | ||||
| Price risk management liabilities |
1,262 | 823 | ||||
| Income taxes payable |
2,252 | 2,567 | ||||
| Current maturities of long-term debt |
31,234 | 30,000 | ||||
| Total current liabilities |
404,917 | 169,967 | ||||
| LONG-TERM DEBT, less current maturities |
1,071,158 | 196,000 | ||||
| OTHER NON-CURRENT LIABILITIES |
845 | 157 | ||||
| DEFERRED TAXES |
216,726 | 55,385 | ||||
| MINORITY INTERESTS |
803,220 | — | ||||
| 2,496,866 | 421,509 | |||||
| COMMITMENTS AND CONTINGENCIES |
||||||
| PARTNERS’ CAPITAL: |
||||||
| General partner capital |
4,053 | 2,118 | ||||
| Limited partners’ capital (194,295,631 and 156,815,788 units authorized, issued and outstanding at August 31, 2004 and 2003, respectively) |
364,261 | 180,513 | ||||
| Accumulated other comprehensive income |
11 | — | ||||
| Total partners’ capital |
368,325 | 182,631 | ||||
| Total liabilities and partners’ capital |
$ | 2,865,191 | $ | 604,140 | ||
The accompanying notes are an integral part of these consolidated financial statements.
F-21
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L. P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except unit and per unit data)
| Year ended August 31, 2004 |
Eleven months ended 2003 |
|||||||
| REVENUES: |
||||||||
| Midstream and transportation |
$ | 1,966,804 | $ | 931,027 | ||||
| Propane |
342,522 | — | ||||||
| Other |
37,631 | — | ||||||
| Total revenues |
2,346,957 | 931,027 | ||||||
| COSTS AND EXPENSES: |
||||||||
| Cost of products sold |
1,981,424 | 825,438 | ||||||
| Operating expenses |
147,374 | 25,046 | ||||||
| Depreciation and amortization |
56,242 | 11,870 | ||||||
| Selling, general and administrative |
31,111 | 13,172 | ||||||
| Total costs and expenses |
2,216,151 | 875,526 | ||||||
| OPERATING INCOME |
130,806 | 55,501 | ||||||
| OTHER INCOME (EXPENSE): |
||||||||
| Interest expense |
(41,217 | ) | (12,453 | ) | ||||
| Equity in earnings of affiliates |
363 | 1,423 | ||||||
| Loss on disposal of assets |
(1,006 | ) | — | |||||
| Gain on Energy Transfer Transactions |
395,253 | — | ||||||
| Other, net |
516 | 202 | ||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE |
484,715 | 44,673 | ||||||
| Minority interests in income from continuing operations |
(35,164 | ) | — | |||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE |
449,551 | 44,673 | ||||||
| Income tax expense |
(2,792 | ) | (4,432 | ) | ||||
| INCOME FROM CONTINUING OPERATIONS |
446,759 | 40,241 | ||||||
| DISCONTINUED OPERATIONS: |
||||||||
| Income from discontinued operations |
6,163 | 5,994 | ||||||
| Minority interests in income from discontinued operations |
(2,705 | ) | — | |||||
| Total income from discontinued operations |
3,458 | 5,994 | ||||||
| NET INCOME |
450,217 | 46,235 | ||||||
| GENERAL PARTNER’S INTEREST IN NET INCOME |
4,438 | 587 | ||||||
| LIMITED PARTNERS’ INTEREST IN NET INCOME |
$ | 445,779 | $ | 45,648 | ||||
| BASIC NET INCOME PER LIMITED PARTNER UNIT |
||||||||
| Limited Partners’ income from continuing operations |
$ | 2.47 | $ | 0.25 | ||||
| Limited Partners’ income from discontinued operations |
0.02 | 0.04 | ||||||
| NET INCOME PER LIMITED PARTNER UNIT |
$ | 2.49 | $ | 0.29 | ||||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
179,162,636 | 156,724,743 | ||||||
| DILUTED NET INCOME PER LIMITED PARTNER UNIT |
||||||||
| Limited Partners’ income from continuing operations |
$ | 1.83 | $ | 0.17 | ||||
| Limited Parters’ income from discontinued operations |
0.01 | 0.02 | ||||||
| NET INCOME PER LIMITED PARTNER UNIT |
$ | 1.84 | $ | 0.19 | ||||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
242,479,820 | 241,441,342 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-22
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
| Year ended August 31, 2004 |
Eleven months August 31, | ||||||
| NET INCOME |
$ | 450,217 | 46,235 | ||||
| OTHER COMPREHENSIVE INCOME: |
|||||||
| Reclassification adjustment for gains on derivative instruments included in net income accounted for as hedges |
(1,211 | ) | — | ||||
| Change in value of derivative instruments accounted for as hedges |
1,241 | — | |||||
| Change in value of available-for-sale securities |
(19 | ) | — | ||||
| Comprehensive income |
$ | 450,228 | $ | 46,235 | |||
| Reconciliation of Accumulated Other Comprehensive Income |
|||||||
| Balance, beginning of period |
$ | — | $ | — | |||
| Current period reclassification to earnings |
(1,211 | ) | — | ||||
| Current period change |
1,222 | — | |||||
| Balance, end of period |
$ | 11 | $ | — | |||
The accompanying notes are an integral part of these consolidated financial statements.
F-23
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except unit data)
| Limited Partner Units |
General Partner’s Capital |
Limited Partners’ Capital |
Accumulated Other Comprehensive Income |
Total Partners’ Capital |
|||||||||||||
| Balance, Inception |
— | $ | — | $ | — | $ | — | $ | — | ||||||||
| Capital contributions |
156,815,788 | 1,579 | 139,637 | 141,216 | |||||||||||||
| Distributions |
— | (48 | ) | (4,772 | ) | — | (4,820 | ) | |||||||||
| Net income |
— | 587 | 45,648 | — | 46,235 | ||||||||||||
| Net change in Accumulated Other Comprehensive Income |
— | — | — | — | — | ||||||||||||
| Balance, August 31, 2003 |
156,815,788 | $ | 2,118 | $ | 180,513 | $ | — | $ | 182,631 | ||||||||
| Vesting of incentive units |
36,437,247 | — | — | — | — | ||||||||||||
| Units issued in exchange for property and subsidiary interests |
1,042,596 | — | 1,743 | — | 1,743 | ||||||||||||
| Distributions |
— | (2,503 | ) | (263,774 | ) | — | (266,277 | ) | |||||||||
| Net income |
— | 4,438 | 445,779 | — | 450,217 | ||||||||||||
| Net change in Accumulated Other Comprehensive Income |
— | — | — | 11 | 11 | ||||||||||||
| Balance, August 31, 2004 |
194,295,631 | $ | 4,053 | $ | 364,261 | $ | 11 | $ | 368,325 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-24
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year ended August 31, 2004 |
Eleven months ended August 31, 2003 |
|||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Net income |
$ | 450,217 | $ | 46,235 | ||||
| Reconciliation of net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization related to continuing and discontinued operations |
58,491 | 13,461 | ||||||
| Amortization of deferred finance costs charged to interest |
2,642 | 2,464 | ||||||
| Provision for loss on accounts receivable |
1,667 | — | ||||||
| Loss on disposal of assets |
1,006 | — | ||||||
| Gain on Energy Transfer Transactions |
(395,253 | ) | — | |||||
| Deferred compensation on restricted units and long-term incentive plan |
42 | — | ||||||
| Undistributed earnings of affiliates |
(363 | ) | (1,423 | ) | ||||
| Deferred income taxes |
(5,413 | ) | (1,116 | ) | ||||
| Other, net |
— | 543 | ||||||
| Minority interests |
38,061 | — | ||||||
| Distributions from subsidiary to minority unitholders |
(39,388 | ) | — | |||||
| Changes in assets and liabilities, net of effect of acquisitions: |
||||||||
| Accounts receivable |
(101,974 | ) | (85,323 | ) | ||||
| Accounts receivable from related companies |
(35 | ) | — | |||||
| Inventories |
35,457 | (373 | ) | |||||
| Deposits paid to vendors |
16,030 | (19,053 | ) | |||||
| Exchanges receivable |
(7,479 | ) | (1,373 | ) | ||||
| Prepaid expenses and other |
2,532 | — | ||||||
| Intangibles and other assets |
(1,360 | ) | 1,964 | |||||
| Accounts payable |
58,278 | 97,270 | ||||||
| Accounts payable to related companies |
685 | (2,538 | ) | |||||
| Exchanges payable |
1,436 | 1,410 | ||||||
| Deposits from customers |
(222 | ) | 11,600 | |||||
| Accrued and other current liabilities |
9,831 | 5,082 | ||||||
| Other long-term liabilities |
688 | 157 | ||||||
| Income taxes payable |
(315 | ) | 1,793 | |||||
| Price risk management liabilities, net |
(3,163 | ) | (105 | ) | ||||
| Net cash provided by operating activities |
122,098 | 70,675 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Cash paid for acquisitions, net of cash acquired |
(622,929 | ) | (340,187 | ) | ||||
| Capital expenditures |
(109,688 | ) | (11,914 | ) | ||||
| Cash invested in affiliates |
(322 | ) | — | |||||
| Dividend from affiliate |
— | 1,000 | ||||||
| Proceeds from the sale of assets |
1,108 | 9,843 | ||||||
| Net cash used in investing activities |
(731,831 | ) | (341,258 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
| Proceeds from borrowings |
894,079 | 246,000 | ||||||
| Principal payments on debt |
(510,182 | ) | (20,000 | ) | ||||
| Net proceeds from issuance of common units of subsidiary |
528,129 | — | ||||||
| Contributions from partners |
— | 110,199 | ||||||
| Distributions to partners |
(266,277 | ) | (4,820 | ) | ||||
| Debt issuance costs |
(8,236 | ) | (5,724 | ) | ||||
| Net cash provided by financing activities |
637,513 | 325,655 | ||||||
| INCREASE IN CASH AND CASH EQUIVALENTS |
27,780 | 55,072 | ||||||
| CASH AND CASH EQUIVALENTS, beginning of period |
55,072 | — | ||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 82,852 | $ | 55,072 | ||||
The accompanying notes are an integral part of these consolidated financial statements
F-25
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)
(in thousands)
| NONCASH INVESTING ACTIVITIES: |
|||||||
| Assets contributed to subsidiaries |
— | $ | (31,017 | ) | |||
| NONCASH FINANCING ACTIVITIES: |
|||||||
| Notes payable incurred on noncompete agreements |
$ | 215 | — | ||||
| Issuance of subsidiary common units in connection with certain acquistions |
$ | 734 | $ | — | |||
| Assets and subsidiary interests contributed by partners |
$ | 1,743 | $ | 31,017 | |||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|||||||
| Cash paid during the period for interest, net of $926 and $0 capitalized for August 31, 2004 and 2003, respectively |
$ | 37,971 | $ | 8,486 | |||
| Cash paid during the period for income taxes |
$ | 7,227 | $ | 2,935 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands)
The accompanying consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries (the “Partnership” or “ETE”) presented herein for the year ended August 31, 2004 and the eleven months ended August 31, 2003 include the results of operations for Energy Transfer Partners, L.P. (“ETP”), which in turn include the results of operations for La Grange Acquisition, L.P. (“ETC OLP”) for the entire periods from September 1, 2003 through August 31, 2004 and from October 1, 2002 through August 31, 2003. However, the results of operations for Heritage Propane Partners, L.P. (Heritage), Heritage Holdings, Inc. (HHI), Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETP, and Energy Transfer Partners, L.L.C. (“ETP LLC”) are only included for the period from January 20, 2004 to August 31, 2004. Thus, the results of operations do not represent the entire results of operations for Heritage, HHI, ETP GP, or ETP LLC for the year ended August 31, 2004, as they do not include the results of operations of Heritage, HHI, ETP GP, or ETP LLC for the period prior to the Energy Transfer Transactions on January 20, 2004. The Energy Transfer Transactions are described in Note 1 below. The comparability of the accompanying consolidated financial statements are also affected by other material acquisitions which are described in Note 2.
1. OPERATIONS AND ORGANIZATION:
The Partnership is a Texas limited partnership, which was formed in September 2002. On August 23, 2005, the Partnership converted from a Texas limited partnership to a Delaware limited partnership. ETE’s partnership agreement contains provisions which govern the relative ownership percentages of the Partnership.
LE GP, LLC, the general partner of ETE, is a Texas limited liability company controlled by common ownership of ETC Holdings, LP (Holdings). LE GP, LLC and the general partner of Holdings are ultimately owned and controlled by the Co-CEOs of ETP, and Natural Gas Partners, a venture capital investor.
Following the Energy Transfer Transactions on January 20, 2004, the Partnership owned all of the equity interests in ETP GP, the general partner of ETP, which entitled the Partnership to receive all of the cash distributions made by ETP GP related to its general partner interest and the related incentive distribution rights of ETP.
In September 2004, the Partnership sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, the Partnership sold a 5% limited partner interest in ETE to this group. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were contributed together with the 4.6662% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interest together were deemed to be an equivalent value of the 5% limited partner interest in ETE. The equivalent value was determined to be the book value of the Common Units and the interests in ETP GP and ETP LLC that were contributed.
Under the terms of ETE’s partnership agreement, the limited partners’ potential liability is limited to their investment in the Partnership. The general partner of ETE manages and controls the business and affairs of the Partnership. The limited partners of ETE are not involved in the management and control of ETE.
Energy Transfer Transactions
On January 20, 2004, ETE and Heritage completed a series of transactions whereby ETE contributed ETC OLP to Heritage in exchange for cash of $300,000 less the amount of ETC OLP debt in excess of $151,500, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by ETE relating to the ETC OLP business prior to closing, $433,909 of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151,500. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and
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Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
accounts receivable to ETE and an affiliate of ETE contributed an office building to ETE. ETE also received 7,485,030 Special Units of Heritage on a post-split basis as consideration for the project ETC OLP had in progress to construct the Bossier Pipeline. The Special Units converted to Heritage’s Common Units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the Special Units to Common Units was approved by Energy Transfer Partners’ Unitholders at a special meeting held on June 23, 2004.
Simultaneously with the Energy Transfer Transactions, ETE obtained control of Heritage by acquiring all of the interest in ETP GP, the general partner of Heritage, and ETP LLC, the general partner of ETP GP, from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30,000 (the General Partner Transaction). In conjunction with the General Partner Transaction, ETP GP contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (HOLP) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) from ETP GP for $100,000.
Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325,000 from financial institutions and Heritage raised $355,948 of gross proceeds through the sale of 9,200,000 Common Units of Heritage at an offering price of $38.69 per unit. The net proceeds were used to finance the transactions and for general partnership purposes.
Subsequent to the Energy Transfer Transactions, Heritage changed its name to Energy Transfer Partners, L.P., and began trading on the New York Stock Exchange under the ticker symbol “ETP”. The name change and new ticker symbol were effective March 1, 2004.
Accounting Treatment of the Energy Transfer Transactions
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards 141, Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETE was the acquirer for accounting purposes. Consequently, the Partnership’s financial statements do not reflect 100% of the results of Heritage, HHI, ETP GP, or ETP LLC within the period, as those results prior to January 19, 2004 (the date of the Energy Transfer Transactions) are not included. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The Partnership, in accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141, recorded a gain of approximately $395,000 as a result of the Energy Transfer Transactions. ETE accounted for the transaction as a partial sale of ETC OLP and a partial acquisition of Heritage, and recognized the gain to the extent ETC OLP was sold and stepped up the assets of ETC OLP to the extent ETC OLP was acquired by the minority shareholders. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by ETE through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%.
The acquisition of HHI by Heritage was accounted for as a capital transaction at ETP as the primary asset held by HHI was 8,853,832 Common Units of ETP on a post-split basis. Following the acquisition of HHI the ETP Common Units held by HHI were converted to Class E Units of ETP.
The issuance of the additional ETP Common Units upon the conversion of ETP Special Units adjusted the percent of Heritage acquired by ETE in the Energy Transfer Transactions and resulted in an additional fair value step-up being recorded on Heritage’s assets in accordance with EITF 90-13. Upon the conversion of the Special Units on June 23, 2004, ETE acquired approximately 41.5% of Heritage.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
The excess purchase price over Heritage’s cost was determined as follows:
| Net book value of Heritage at January 20, 2004 |
$ | 239,102 | ||
| Historical goodwill at January 20, 2004 |
(170,500 | ) | ||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 267,210 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Equity interest acquired |
$ | 110,892 | ||
| Fair market value of Limited Partner Units |
668,534 | |||
| Purchase price of General Partner Interest |
30,000 | |||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 897,142 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Fair value of equity acquired |
372,314 | |||
| Net book value of equity acquired |
110,892 | |||
| Excess purchase price over Heritage cost |
$ | 261,422 | ||
The excess purchase price over Heritage cost was allocated as follows:
| Property, plant and equipment (25 year life) |
$ | 35,269 | |
| Customer lists (15 year life) |
18,926 | ||
| Trademarks |
19,251 | ||
| Goodwill |
187,976 | ||
| $ | 261,422 | ||
Goodwill was warranted in the Energy Transfer Transactions because the business enterprise value of the operations acquired exceeded the fair market value of the tangible and identifiable intangible assets acquired. The allocation of the purchase price reflects the final assessment of asset values of Heritage acquired in the Energy Transfer Transactions.
The gain recognized by ETE as a result of the Energy Transfer Transactions was determined as follows:
| ETE’s historical basis in ETC OLP |
$ | (90,906 | ) | |
| Percent sold in Energy Transfer Transactions |
58.5 | % | ||
| (53,180 | ) | |||
| Fair value of Heritage equity acquired in Energy Transfer Transactions |
372,314 | |||
| Less Consideration paid for ETP’s GP interest |
$ | (30,000 | ) | |
| Fair value of assets received in Energy Transfer Transactions |
$ | 342,314 | ||
| Gain on partial sale of ETC OLP |
$ | 395,494 | ||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE in the Energy Transfer Transactions of approximately 58.5%, determined in accordance with Emerging Issues Task Force EITF 90-13 and SFAS 141. The step up resulted in an approximate $504,000 increase to property, plant and equipment at ETE which is being depreciated over estimated lives 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributable to a taxable subsidiary of ETC OLP, resulting in approximately $108.5 million of deferred tax liabilities recorded by ETE. The deferred tax liabilities will reverse at the same rate as the related step-up in assets will be depreciated.
Accounting Treatment of the General Partner Transaction
Goodwill of $29,589 was recorded in connection with ETE’s acquisition of ETP GP. Goodwill was warranted because, as the General Partner of ETP, ETP GP owns certain incentive distribution rights, which entitle it to receive distributions in excess of its 2% general partner interest in ETP.
Business Operations
Subsequent to the Energy Transfer Transactions described above, ETE conducts business operations only through the two wholly owned operating partnerships of ETP: ETC OLP and HOLP, (collectively the “Operating Partnerships”).
ETC OLP is engaged in midstream natural gas and transportation operations. ETC OLP owns and operates natural gas gathering, natural gas intrastate pipeline systems, and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and Louisiana. ETC OLP is a Texas limited partnership formed in October 2002 and was 99.9% owned by the Partnership prior to the Energy Transfer Transactions and is 99.9% owned by ETP subsequent to the Energy Transfer Transactions and 0.1% owned by ETC OLP’s general partner LA GP, LLC, a wholly-owned subsidiary of ETP. ETC OLP is the 99.9% limited partner to ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Oklahoma Pipeline Ltd (the “Elk City System”), which was sold on April 14, 2005, ETC Katy Pipeline, Ltd., ETC Processing, Ltd. and ETC Marketing, Ltd. and the 99% limited partner to ETC Oasis Pipe Line, L.P. and ET Company I, Ltd (collectively, the “Operating Companies”). ETC Oklahoma Pipeline Ltd is presented as discontinued operations in the Partnership’s consolidated financial statements. ETC OLP also owns a 50% interest in Vantex Gas Pipeline Company, LLC, a 50.5% interest in Vantex Energy Services, Ltd., and a 49% interest in Ranger Pipeline, L.P. These investments are accounted for under the equity method of accounting as ETC OLP exercises significant influence over these entities but lacks controlling interests. On June 29, 2005, ETP bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd. Prior to December 27, 2002 when the remaining 50% of Oasis Pipe Line Company (“Oasis”) capital stock was redeemed, ETE accounted for its 50% ownership in Oasis under the equity method. ETC OLP purchased the remaining 50% interest in Oasis on December 27, 2002, and Oasis became a wholly-owned subsidiary of ETC OLP. ETC OLP was contributed to Heritage on January 19, 2004, to become a wholly-owned subsidiary of ETP.
As of August 31, 2004, ETC OLP owned and operated approximately 5,950 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 4.7 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Its major asset groups consist of the Southeast Texas System, Elk City System, Oasis Pipeline, East Texas Pipeline and the former TUFCO System which is referred to as the ET Fuel System.
HOLP, a Delaware limited partnership, is engaged in retail and wholesale propane operations. As of August 31, 2004, HOLP sold propane and propane-related products to more than 650,000 active residential,
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
commercial, industrial, and agricultural customers in 32 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership is a Canadian partnership, in which HOLP owns a 60% interest, engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly owned subsidiary, Heritage Energy Resources, L.L.C. (Resources).
2. PRESENTATION OF FINANCIAL INFORMATION:
Principles of Consolidation
ETE was formed on October 1, 2002, and has an August 31 year-end. ETE’s predecessor entities had a December 31 year-end. Accordingly, ETE’s eleven-month period ended August 31, 2003 was treated as a transition period under the rules of the Securities and Exchange Commission and therefore, only an eleven-month period is presented for the period ended August 31, 2003. The accompanying combined financial statements of ETE as of August 31, 2003 include the accounts of ETE combined with the accounts of ETC OLP and the Operating Companies after the elimination of significant intercompany balances and transactions.
The accompanying consolidated financial statements for the year ended August 31, 2004 include the results of operations for ETE consolidated with the results of operations of ETC OLP and the Operating Companies, beginning September 1, 2003, and the results of operations of ETP, HOLP, HHI, ETP GP, and ETP LLC beginning January 20, 2004. On June 2, 2004, ETC OLP acquired the ET Fuel System from TXU Fuel Company, a subsidiary of TXU Corp. The accompanying financial statements for the year ended August 31, 2004 include the results of operations of the ET Fuel System beginning June 2, 2004 and the Bossier Pipeline since June 21, 2004.
A minority interest liability and minority interest expense is recorded for all partially owned subsidiaries.
During the eleven months ended August 31, 2003, ETC OLP owned the Southeast Texas System, the Oasis Pipeline, and the Elk City System. From October 1, 2002 through December 27, 2002, ETC OLP also owned a 50% equity interest in Oasis Pipe Line Company, which owns the Oasis Pipeline. After December 27, 2002, ETC OLP owned a 100% interest in Oasis Pipe Line Company. In addition, on December 27, 2002, an affiliate of the Partnership’s general partner contributed to ETC OLP its marketing business (ET Company I) and its interest in the Vantex System, the Rusk County Gathering System, the Whiskey Bay System and the Chalkley Transmission System.
The following unaudited pro forma consolidated results of operations are presented as if the ET Fuel System, Oasis Pipe Line Company and ET Company I were wholly owned at the beginning of the periods presented and the Energy Transfer Transactions had been made at the beginning of the periods presented.
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 | |||||
| Revenues |
$ | 2,658,143 | $ | 1,704,826 | ||
| Net income |
$ | 82,230 | $ | 35,438 | ||
| Basic earnings per Limited Partner Unit |
$ | 0.42 | $ | 0.18 | ||
| Diluted earnings per Limited Partner Unit |
$ | 0.34 | $ | 0.15 | ||
The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma consolidated results include income from discontinued operations and
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
the gain on the sale of discontinued operations and exclude the gain on the Energy Transfer Transactions. The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. The Partnership considers cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Marketable Securities
Marketable securities owned by ETP and its subsidiaries are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at their fair values. Unrealized holding losses were $53 for the year ended August 31, 2004 and $0 for the eleven months ended August 31, 2003. The Partnership’s share of unrealized losses on available-for-sale securities of $19 for the year ended August 31, 2004 is recorded through other comprehensive income until any unrealized losses are determined to be other than temporary or the marketable securities are sold.
Accounts Receivable
ETC OLP’s midstream and transportation operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). ETP’s management reviews midstream and transportation accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation operations. ETP’s management believes that the occurrence of bad debt in ETC OLP’s midstream and transportation segments is not significant; therefore, an allowance for doubtful accounts for the midstream and transportation segments was not deemed necessary at August 31, 2004 or August 31, 2003. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. The bad debt expense recorded during the year ended August 31, 2004 was $123 and $0 for the eleven months ended August 31, 2003 in the midstream and transportation segments.
ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
HOLP grants credit to its customers for the purchase of propane and propane-related products. Also included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane and liquids marketing activities are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts. ETP’s management’s assessment is based on the overall creditworthiness of HOLP’s customers and any specific disputes. Accounts receivable consisted of the following, excluding amounts related to discontinued operations:
| August 31, 2004 |
August 31, 2003 | ||||||
| Accounts receivable midstream and transportation |
$ | 206,023 | $ | 97,772 | |||
| Accounts receivable propane |
46,990 | — | |||||
| Less—allowance for doubtful accounts |
(1,667 | ) | — | ||||
| Total, net |
$ | 251,346 | $ | 97,772 | |||
The activity in the allowance for doubtful accounts for the retail and wholesale propane segments for periods presented, consisted of the following:
| August 31, 2004 |
August 31, 2003 | |||||
| Balance, beginning of period |
$ | — | $ | — | ||
| Provision for loss on accounts receivable |
1,667 | — | ||||
| Accounts receivable written off, net of recoveries |
— | — | ||||
| Balance, end of period |
$ | 1,667 | $ | — | ||
Inventories
Midstream and transportation inventories are valued at market prices. These amounts turn over monthly and ETP’s management believes the costs approximate market value. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following, excluding amounts related to discontinued operations:
| August 31, 2004 |
August 31, 2003 | |||||
| Natural gas, propane and other NGLs |
$ | 40,926 | $ | 1,813 | ||
| Appliances, parts and fittings and other |
12,335 | 2,071 | ||||
| Total inventories |
$ | 53,261 | $ | 3,884 | ||
Deposits
Deposits are paid to vendors in ETP’s midstream and transportation business as prepayments for natural gas deliveries in the following month. ETC OLP makes prepayments when the volume of business with a vendor exceeds ETP’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $3,000 as of August 31, 2004 and $16,962 as of August 31, 2003. ETP also has deposits with derivative counterparties of $23 as of August 31, 2004 and $2,091 as of August 31, 2003.
Deposits are received from ETP’s midstream and transportation customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane use.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Prepayments and security deposits may also be required when ETP’s customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $11,378 as of August 31, 2004 and $11,600 as of August 31, 2003.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on the Partnership’s consolidated balance sheet. Management believes market value approximates cost.
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Partnership capitalizes certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.
The Partnership reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the periods presented.
Components and useful lives of property, plant and equipment were as follows, excluding assets held for sale:
| August 31, 2004 |
August 31, 2003 |
|||||||
| Land and improvements |
$ | 28,156 | $ | 992 | ||||
| Buildings and improvements (10 to 30 years) |
37,201 | 992 | ||||||
| Pipelines and equipment (10 to 65 years) |
1,279,755 | 348,874 | ||||||
| Natural gas storage (40 years) |
24,277 | — | ||||||
| Bulk storage, equipment and facilities (3 to 30 years) |
52,007 | — | ||||||
| Tanks and other equipment (5 to 30 years) |
321,511 | — | ||||||
| Vehicles (5 to 10 years) |
56,740 | 883 | ||||||
| Right of way (20 to 65 years) |
65,924 | 3,954 | ||||||
| Furniture and fixtures (3 to 10 years) |
7,324 | 273 | ||||||
| Linepack |
12,802 | 5,128 | ||||||
| Pad gas |
42,136 | — | ||||||
| Other (5 to 10 years) |
5,581 | 1,316 | ||||||
| 1,933,414 | 362,412 | |||||||
| Less—Accumulated depreciation |
(61,051 | ) | (12,083 | ) | ||||
| 1,872,363 | 350,329 | |||||||
| Plus—Construction work-in-process |
42,911 | 3,980 | ||||||
| Property, plant and equipment, net |
$ | 1,915,274 | $ | 354,309 | ||||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate. During the year ended August 31, 2004 $926 of interest was capitalized for pipeline construction projects, and no interest was capitalized the eleven months ended August 31, 2003.
Asset Retirement Obligation
ETP accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, (SFAS 143). SFAS No. 143 requires ETP to record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, an entity would recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.
ETP’s management has completed the assessment of SFAS 143, and has determined that ETP is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2004 or August 31, 2003 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.
Investment in Affiliates
ETC OLP owns a 50% interest in Vantex Gas Pipeline Company, LLC, and a 50.5% interest in Vantex Energy Services, Ltd. The Partnership accounts for these investments under the equity method of accounting. The Vantex system is located in East Texas and is composed of approximately 250 miles of pipeline. Vantex Energy Services provides energy related marketing services to small and medium sized producers and end users on the Vantex Gas Pipeline system. On June 29, 2005 ETP bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd.
ETC OLP also owns a 49% interest in Ranger Pipeline, L.P. (Ranger), which owns a 50% interest in Mountain Creek Joint Venture (Mountain Creek). Mountain Creek is located in North Texas and is composed of approximately 15 miles of pipeline. Mountain Creek supplies gas to an electric generation plant and earns the majority of its yearly income between the months of June and October. The Partnership accounts for its investment in Ranger using the equity method of accounting.
Prior to December 27, 2002, when the remaining 50% of Oasis Pipe Line capital stock was redeemed, the Partnership accounted for its initial 50% ownership in Oasis Pipe Line under the equity method. The Partnership recognized $1.6 million of equity method income from the investment in Oasis Pipe Line in 2003 prior to December 27, 2002. Oasis Pipe Line results from operations are recognized on a consolidated basis effective January 1, 2003.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Goodwill
Goodwill is associated with acquisitions made for the Partnership’s midstream, retail propane and other segments. Other segments related to the acquisition of ETP GP. Of the $348,761 balance in goodwill, $25,442 is expected to be tax deductible. The changes in the carrying amount of goodwill for the year ended August 31, 2004 and the eleven months ended August 31, 2003 were as follows:
| Midstream |
Transportation |
Retail Propane |
Other |
Total | |||||||||||
| Balance as of October 1, 2002 (inception) |
$ | — | — | $ | — | $ | — | $ | — | ||||||
| Goodwill acquired during the year |
13,409 | — | — | — | 13,409 | ||||||||||
| Balance as of August 31, 2003 |
$ | 13,409 | — | $ | — | $ | — | $ | 13,409 | ||||||
| Goodwill acquired during the year |
— | 10,327 | 295,469 | 29,556 | 335,352 | ||||||||||
| Impairment losses |
— | — | — | — | |||||||||||
| Balance as of August 31, 2004 |
$ | 13,409 | $ | 10,327 | $ | 295,469 | $ | 29,556 | $ | 348,761 | |||||
The Partnership assesses the impairment of its goodwill in accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS 142”), by determining whether the carrying amount exceeds the fair value of the recognized goodwill asset. If impairment has occurred, the difference between the carrying amount and the fair value is recognized as a loss in the consolidated statement of operations in the period of the impairment. Based on the annual impairment test performed as of August 31, 2004 and 2003, there was no impairment.
Intangibles and Other Assets
Intangibles and other assets are stated at cost net of amortization computed on the straight-line method. The Partnership eliminates from its balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other assets were as follows:
| August 31, 2004 |
August 31, 2003 |
|||||||||||||
| Gross Carrying Amount |
Accumulated Amortization |
Gross Carrying Amount |
Accumulated Amortization |
|||||||||||
| Amortized intangible assets— |
||||||||||||||
| Noncompete agreements (5 to 15 years) |
$ | 27,952 | $ | (3,006 | ) | $ | — | $ | — | |||||
| Customer lists (15 years) |
46,691 | (2,307 | ) | — | — | |||||||||
| Financing costs (3 to 15 years) |
18,125 | (5,515 | ) | 5,724 | (2,464 | ) | ||||||||
| Consulting agreements (2 to 7 years) |
132 | (29 | ) | — | — | |||||||||
| Other (10 years) |
477 | (143 | ) | 477 | (92 | ) | ||||||||
| Total |
$ | 93,377 | $ | (11,000 | ) | $ | 6,201 | $ | (2,556 | ) | ||||
| Unamortized intangible assets— |
||||||||||||||
| Trademarks |
26,818 | — | — | — | ||||||||||
| Other assets |
2,083 | — | — | — | ||||||||||
| Total intangibles and other assets |
$ | 122,278 | $ | (11,000 | ) | $ | 6,201 | $ | (2,556 | ) | ||||
Aggregate amortization expense of intangible assets was $8,444 for the year ended August 31, 2004 and $2,556 for the eleven months ended August 31, 2003. Included in interest expense was $2,642 and $2,311 from
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
amortization of deferred financing fees for the year ended August 31, 2004 and the eleven months ended August 31, 2003, respectively. The estimated aggregate amortization expense for the next five fiscal years is $11,140 for 2005; $10,560 for 2006; $10,170 for 2007; $7,630 for 2008, and $6,075 for 2009.
The Partnership reviews other intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of other intangible assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of other intangible assets has been recorded as of August 31, 2004 or 2003.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following, excluding liabilities associated with discontinued operations:
| August 31, 2004 |
August 31, 2003 | |||||
| Interest payable |
$ | 6,633 | $ | 1,014 | ||
| Wages, payroll taxes and employee benefits |
15,975 | 2,666 | ||||
| Deferred tank rent |
4,581 | — | ||||
| Taxes other than income |
6,921 | 2,189 | ||||
| Advanced budget payments and unearned revenue |
33,299 | — | ||||
| Other |
6,353 | 2,038 | ||||
| Accrued and other current liabilities |
$ | 73,762 | $ | 7,907 | ||
Fair Value
The carrying amounts of accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to the Partnership or its subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2004 was $1,128,536 and $1,102,393 respectively. At August 31, 2003 the carrying amount of long-term debt approximated its fair value.
Revenue Recognition
Revenues for sales of natural gas, NGLs, including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor, transportation, treating, compression, and gas processing, is recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Tank rent is recognized ratably over the period it is earned.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
ETP also utilizes other types of arrangements in its midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and processes natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Its contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
Primarily the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines determines transportation segment results. Under transportation contracts, ETP’s customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay ETP even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer on the Oasis Pipeline, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly.
Shipping and Handling Costs
In accordance with the Emerging Issues Task Force Issue 00-10, Accounting for Shipping and Handling Fees and Costs, ETP has classified $35,895 and $10,883 from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue for the year ended August 31, 2004 and the eleven months ended August 31, 2003 respectively. Costs related to fuel sold are included in cost of sales, while the remaining costs of approximately $19,834 and $8,879 included in operating expenses reflect the cost of fuel consumed for compression and treating for the year ended August 31, 2004 and the eleven months ended August 31, 2003 respectively. HOLP does not separately charge shipping and handling costs of propane to customers.
Costs and Expenses
Costs of products sold include actual cost of fuel sold adjusted for the effects of the Partnership’s hedging and other commodity derivative activities, storage fees and inbound freight on propane, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs related to propane, purchasing costs, and plant operations. Selling, general and administrative expenses include all corporate expenses and compensation for corporate personnel.
Gain on Issuances of Subsidiary Units
The Partnership has elected not to record gains arising from issuances of units by ETP as permitted by SEC Staff Accounting Bulletin No. 51. If ETP issues units at a price less than the Partnership’s carrying value per unit, the Partnership assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. The Partnership did not recognize any impairments related to the issuance of ETP units during the year ended August 31, 2004 or the eleven months ended August 31, 2003.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Income Taxes
ETE is a limited partnership. As a result, the Partnership’s earnings or losses for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement.
Oasis, Heritage Holdings, and certain other of the Partnership’s subsidiaries are taxable corporations and follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.
Income Per Limited Partner Unit
Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of units outstanding. Diluted net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of units outstanding and the weighted average number of ETE Incentive Units granted. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 | |||||
| Basic Net Income per Limited Partner Unit: |
||||||
| Limited Partners’ interest in net income |
$ | 445,779 | $ | 45,648 | ||
| Weighted average limited partner units |
179,162,636 | 156,724,743 | ||||
| Limited Partners’ income from continuing operations |
$ | 2.47 | $ | 0.25 | ||
| Limited Partners’ income from discontinued operations |
0.02 | 0.04 | ||||
| Basic net income per limited partner unit |
$ | 2.49 | $ | 0.29 | ||
| Diluted Net Income per Limited Partner Unit: |
||||||
| Limited partners’ interest in net income |
$ | 445,779 | $ | 45,648 | ||
| Weighted average limited partner units |
179,162,636 | 156,724,743 | ||||
| Dilutive effect of Incentive units |
63,317,184 | 84,716,599 | ||||
| Weighted average limited partner units, assuming dilutive effect of Employee Incentive units |
242,479,820 | 241,441,342 | ||||
| Limited Partners’ income from continuing operations |
$ | 1.83 | $ | 0.17 | ||
| Limited Partners’ income from discontinued operations |
0.01 | 0.02 | ||||
| Diluted net income per limited partner unit |
$ | 1.84 | $ | 0.19 | ||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Employee Incentive Interests
ETE’s partnership agreement as amended and restated provides for certain incentive interests for certain employees. The employee incentive interests consists of 12,145,749 Employee Incentive Units granted to certain employees on the formation of ETE (the “Employee Incentive Units”).
The Employee Incentive Units vest ratably over a three-year period from the date of grant or fully vest upon the occurrence of a Fundamental Change as defined in ETE’s partnership agreement. The Employee Incentive Units were limited partner interests in ETE (as defined in the amended and restated agreement of limited partnership of ETE) and afforded the recipients with certain rights as limited partners in accordance with their terms.
The Partnership accounts for the Employee Incentive Interests in accordance with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123). Under SFAS 123, total compensation is measured at the fair value of the award on the grant date and compensation expense is recorded ratably over the service period. Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive prior to vesting of the Employee Incentive Interests. Accordingly, no expense was recorded in the Partnership’s 2004 or 2003 consolidated financial statements, and no expense related to the Employee Incentive Units issued upon formation of ETE will be recorded in any subsequent period.
As a result of The Energy Transfer Transactions in January 2004, all Employee Incentive Units vested and were converted to limited partner interests, and the “Tier I Payout” was met giving effective rights as a limited partner in ETE to the holders of the Employee Incentive Units who ceased to be employees of ETE and became employees of ETP and its subsidiaries. In May 2005, ETE exchanged 631,320 ETP Common Units held by ETE and $1,046 in cash for the redemption of 4,858,300 limited partner interests in ETE, which were then retired. The redemption was determined to be no more than the fair value of the respective interests in ETE.
Other Incentive Interests
ETE’s partnership agreement provides for 72,874,494 Incentive Units (the ETE Incentive Units), consisting of: 24,291,498 “Tier I Units;” 12,145,749 “Tier II Units;” 12,145,749 “Tier III Units;” and 24,291,498 “Tier IV Units;” to be granted to ETC Holdings, LP, one of ETE’s limited partners, if certain “Tier” payouts are achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 24,291,498 ETE Incentive Units vested and were converted to limited partner interests. In June 2005, the remaining “Tier” payout conditions as defined in the Partnership Agreement were achieved and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership.
ETP Restricted Unit Plan
Effective March 15, 2005 ETP declared a two-for-one split of its Common Units. The units discussed in the Restricted Unit Plan and the Long-Term Incentive Plan footnotes are reflected on a post-split basis.
ETP GP previously adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan (the Restricted Unit Plan), for certain directors and key employees of ETP GP and its affiliates. The Restricted Unit Plan provided rights to acquire up to 292,000 Common Units of ETP. The Restricted Unit Plan provided for the award or grant to key employees of the right to acquire Common Units of ETP on such terms and conditions (including vesting
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
conditions, forfeiture or lapse of rights) as the Compensation Committee of ETP GP (the Compensation Committee) shall determine. In addition, eligible directors automatically received a director’s grant of 1,000 Common Units on each September 1, and newly elected directors were also entitled to receive a grant of 4,000 Common Units upon election or appointment to ETP’s Board. Directors of ETP who were ETP employees or employees of ETP GP were not entitled to receive a director’s grant of Common Units of ETP but could receive ETP Common Units as employees.
Generally, awards granted under the Restricted Unit Plan vested upon the occurrence of specified performance objectives established by the Compensation Committee at the time designations of grants were made, or if later, the three-year anniversary of the grant date. In the event of a “change of control” (as defined in the Restricted Unit Plan), all rights to acquire ETP Common Units pursuant to the Restricted Unit Plan immediately vested. Pursuant to the January 2004 acquisition of ETP GP by ETE, the change of control provisions of the Restricted Unit Plan were triggered, resulting in the early vesting of 43,200 units by Heritage. Individuals holding 9,000 grants waived their rights to early vesting under the change of control provisions.
The issuance of ETP Common Units pursuant to the Restricted Unit Plan was intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of ETP’s Common Units. Therefore, no consideration was payable by the plan participants upon vesting and issuance of ETP’s Common Units. Following the June 23, 2004 approval of the 2004 Unit Plan at the special meeting of ETP Unitholders, the Restricted Unit Plan was terminated (except for the obligation to issue Common Units at the time the 16,592 units previously awarded vest), and no additional grants will be made under the Restricted Unit Plan.
Deferred compensation expense recognized under the Restricted Unit Plan for the year ended August 31, 2004 was $42 and no compensation expense was recognized for the eleven months ended August 31, 2003.
The Partnership follows the fair value recognition provisions of SFAS 123. SFAS 123 requires that significant assumptions be used during the year to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. ETP assumed a weighted average risk free interest rate of 2.35% for the year ended August 31, 2004, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. The average fair value of the awards granted during fiscal 2004 was $31.88. Annual average cash distributions at the grant date were estimated to be $2.22 for the year ended August 31, 2004. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. There were no grants outstanding at August 31, 2003.
ETP Long Term Incentive Plan
Effective September 1, 2000, ETP GP adopted a long-term incentive compensation plan whereby ETP Common Units were to be awarded to the Executive Officers of ETP GP upon achieving certain targeted levels of Distributed Cash (as defined in the Long Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years Distributed Cash per unit. A minimum of 500,000 units on a post-split basis and if targeted levels were achieved, a maximum of 1,000,000 units were available for award under the Long Term Incentive Plan. In connection with the acquisition by ETE of ETP GP in January 2004, 300,036 units vested and Common Units were issued, and the Long-Term Incentive Plan terminated. No compensation expense was recognized under the Long Term Incentive Plan for the year ended August 31, 2004 or for the eleven months ended August 31, 2003.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
ETP 2004 Unit Plan
On June 23, 2004 at a special meeting of the Common Unitholders of ETP, ETP’s Common Unitholders approved the terms of ETP’s 2004 Unit Plan (the Plan), which provides for awards of ETP Common Units and other rights to ETP’s employees, officers, and directors. The maximum number of ETP Common Units that may be granted under this Plan is 1,800,000 total units issued. Any awards that are forfeited or which expire for any reason, or any units which are not used in the settlement of an award will be available for grant under the Plan. Units to be delivered upon the vesting of awards granted under the Plan may be (i) units acquired by ETP in the open market, (ii) units already owned by ETP or its General Partner, (iii) units acquired by ETP or its General Partner directly from ETP, or any other person, (iv) units that are registered under a registration statement for this Plan, (v) Restricted Units, or (vi) any combination of the foregoing.
Employee Grants. The Compensation Committee of ETP, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any Change in Control as defined by the Plan or upon such terms as the Compensation Committee may require at the time the award is granted. As of August 31, 2004, no grants of awards had been made to any employee under the 2004 Unit Plan. As of May 31, 2005, awards totaling 259,200 units were made under the 2004 Unit Plan to employees, including executive officers. These awards will vest subject to vesting over a three-year period based upon the achievement of certain performance criteria. Vested awards will convert into ETP Common Units upon the third anniversary of the measuring date for the grants, which is September 1 of each year. Vesting occurs based upon the total return to ETP’s Unitholders as compared to a group of Master Limited Partnership peer companies. The issuance of ETP Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units.
Director Grants. Each director of ETP GP who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (Director Participant), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 4,000 ETP Common Units (the Initial Director’s Grant). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of ETP Common Units equal to $15,000 divided by the fair market value of an ETP Common Units on such date (Annual Director’s Grant). Each grant of an award to a Director Participant will vest at the rate of 20% per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. As of May 31, 2005, initial Director’s Grants totaling 16,844 Units have been made.
Long-Term Incentive Grants. The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of August 31, 2004, there has been no Long-Term Incentive Grants made under the Plan.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
This Plan will be administered by the Compensation Committee of the Board of Directors of ETP LLC and may be amended from time to time by the Board; provided however, that no amendment will be made without the approval of a majority of the Unitholders (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the Plan; (iii) materially increase the cost of the Plan to the Partnership; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later that the 10th anniversary of its original effective date.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, deferred taxes, and fair values of unit based compensation. Actual results could differ from those estimates.
Accounting for Derivative Instruments and Hedging Activities
The Partnership applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Partnership has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. As of August 31, 2004, these hedging instruments had a net fair value of $85, which was recorded as price risk management assets and liabilities on the balance sheet through other comprehensive income net of minority interest. The Partnership reclassified into earnings gains of $1,211 after minority interest for the year ended August 31, 2004 related to the commodity financial instruments, that were previously reported in accumulated other comprehensive income (loss). The amount of hedge ineffectiveness recognized in income by ETP was a gain of $895 for the year ended August 31, 2004. At August 31, 2003, no positions had been formally designated as hedges.
In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.
Recently Issued Accounting Standards
In January of 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51 (FIN 46). In December 2003, the FASB issued FIN 46R, which clarified certain issues identified in FIN 46. FIN 46R requires an entity to consolidate a variable interest entity if the entity is designated as the primary beneficiary of that variable interest entity even if the entity does not have a majority of voting interest. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception of any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after March 15, 2004. The implementation of FIN 46 did not have an impact on the Partnership’s consolidated financial position or results of operations.
As of August 31, 2004 and 2003, the Partnership owned various unconsolidated entities in which its share of the unconsolidated entities ranges from 49% to 50%. The Partnership accounts for its investments under the equity method of accounting as prescribed by APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. The Partnership does not control these entities, and each partner shares in all profits and losses equal to their respective share in the entities. There are no limits on the exposure to losses or on the ability to share in returns. Based on the analysis performed, the Partnership is not the primary beneficiary of the entities, and as a result, will not consolidate the entities but will continue to account for the investments in these entities under the equity method.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (SFAS 150). SFAS 150 establishes standards for how an issuer
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS 150 as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Partnership adopted the provisions of SFAS 150 as of September 1, 2003. The adoption did not have a material impact on the Partnership’s consolidated financial position or results of operations.
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require the Partnership to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Partnership’s consolidated financial statements.
SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The Partnership does not expect SFAS 123R to have a material impact on its consolidated results of operations, cash flows or financial position.
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The Partnership accounted for the sale of ETP’s discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.
EITF Issue No. 03-6 (“EITF 03-6). “Participating Securities and the Two-Class method under FASB Statement No. 128.” EITF 03-6 requires the calculation of net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings, as if all of the earnings for the period had been distributed. In periods with undistributed earnings above certain levels, the calculation according to the two-class method results in an increased allocation of undistributed earnings to the general partner of ETP and a dilution of the earnings to the limited partners. In periods that may have year-to-date net losses the allocation of the net losses to the limited partners and the general partner of ETP will be determined based on the same allocation basis specified in the ETP Partnership Agreement that would apply to periods in which there were no undistributed earnings. ETP follows the requirements of EITF 03-6 in calculating their net earnings per limited partner unit and EITF 03-6 is not applicable to ETE.
4. ACQUISITIONS:
Fiscal year 2004 acquisitions
On June 2, 2004, ETC OLP acquired the transportation assets of TXU Fuel Company (formerly the TUFCO System now referred to as the ET Fuel System) for $498,571 in cash. The assets include approximately 2,000 miles of intrastate pipeline and related storage facilities located in Texas, with a total system capacity of 1.3 billion cubic feet or natural gas per day. The purchase price was funded with borrowings under ETC OLP’s amended debt agreement.
These assets allow ETC OLP to provide multiple services to producers in four major producing areas of Texas, as well as providing access to major natural gas markets. In addition, these assets are expected to provide significant growth opportunities for the Partnership going forward. The acquisition was accounted for using the purchase method. The purchase price was initially allocated based on the estimated fair values of the individual assets acquired and the liabilities assumed at the date of the acquisition. The final allocation of the purchase price was completed in the third quarter of fiscal year 2005 upon the completion of an independent appraisal. The results of operations for the ET Fuel System are included in the consolidated income statements beginning on June 2, 2004.
The unaudited pro forma results of operations as if the ET Fuel System had been acquired at the beginning of the periods presented are included in the pro forma results presented in Note 2 to the consolidated financial statements.
During the period from January 20, 2004 to August 31, 2004, HOLP acquired substantially all of the assets of three propane companies, which included Edwards Propane of Marshville, North Carolina, Custer Gas Service of Custer, South Dakota, and one other small company. The aggregate purchase price for these acquisitions totaled $16,967, which included liabilities assumed of $268. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. These acquisitions were financed primarily with the HOLP Senior Revolving Acquisition facility and were accounted for by the purchase method under SFAS 141.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Fiscal year 2003 acquisitions
In October 2002, ETC OLP purchased certain operating assets from Aquila Gas Pipeline, primarily natural gas gathering, treating and processing assets in Texas and Oklahoma, for $263,676 in cash. At the closing of the acquisition of Aquila Gas Pipeline’s assets, $5,000 was put into escrow until such time that proper consents and conveyance could be achieved related to a sales contract. It was later determined that it was unlikely that a proper conveyance could be achieved which resulted in the escrowed amount of $5,000 being returned to ETC OLP during the eleven months ended August 31, 2003. The return of the $5,000 purchase price reduced ETC OLP’s basis in property, plant and equipment.
In connection with the Aquila Gas Pipeline acquisition, ETC OLP acquired a 50% ownership interest in Oasis Pipeline Company and accounted for it under the equity method. On December 27, 2002 Oasis Pipeline Company redeemed the remaining 50% of its capital stock owned by Dow Hydrocarbons Resources, Inc. for $87,000 and cancelled the stock which resulted in ETC OLP owning 100% of the capital stock of Oasis Pipeline effective December 27, 2002.
Acquisitions subsequent to August 31, 2004
In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Gas Services for $64,632 in cash, which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $66,667 which included $64,632 of cash paid and liabilities assumed of $2,035. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets were integrated into ETP’s Southeast Texas System and are expected to provide increased throughput capacity to ETP’s existing midstream assets. The acquisition was not material for pro forma disclosure purposes.
In January 2005, ETP acquired the controlling interests in Houston Pipeline System and related storage facilities (“HPL”) from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350,000 of ETP Common Units. In addition, ETP acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing which was re-paid in full on April 14, 2005. The total purchase price of $1,410,189 which included $1,039,358 of cash paid, net of cash acquired and liabilities assumed of $413,270, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Included in prepaid expenses and other on the consolidated balance sheet as of May 31, 2005 is $42,400 in receivables due from AEP related to the HPL acquisition. Under the terms of the transaction, ETP, through ETC OLP, its wholley-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables ETP to expand its current transportation systems into areas where it previously did not have a presence, and in combination with ETP’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in ETP’s transportation and storage operating segment.
During the nine months ended May 31, 2005, HOLP acquired substantially all of the assets of seven propane businesses. The aggregate purchase price for these acquisitions totaled $18,109 which included $13,875 of cash paid, net of cash acquired, 120,550 ETP Common Units on a post-split basis valued at $2,500 when issued and liabilities assumed of $1,734. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for these acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Assets acquired and purchase price allocation
The assets acquired and purchase price allocation of the Partnership’s acquisitions for the years ended August 31, 2004 and August 31, 2003 were as follows:
| Oasis |
ET Fuel System June 2, 2004 |
Aquila Gas Pipeline October 2002 |
HOLP acquisitions (aggregated) January 20, 2004 to August 31, 2004 | ||||||||||||
| Accounts receivable |
$ | — | $ | — | $ | — | $ | 1,612 | |||||||
| Inventory |
— | — | 1,626 | 335 | |||||||||||
| Other current assets |
— | 57 | 194 | — | |||||||||||
| Investment in unconsolidated affiliate |
— | — | 51,270 | — | |||||||||||
| Property, plant and equipment |
134,040 | 499,789 | 208,374 | 8,024 | |||||||||||
| Intangibles |
— | 1,560 | |||||||||||||
| Goodwill |
— | 10,327 | — | 5,437 | |||||||||||
| Total assets acquired |
134,040 | 510,173 | 261,464 | 16,968 | |||||||||||
| Accounts payable |
— | — | — | — | |||||||||||
| Accrued expenses |
— | (758 | ) | (2,788 | ) | 52 | |||||||||
| Other current liabilities |
— | — | — | 1 | |||||||||||
| Deposits from vendor |
— | (750 | ) | — | — | ||||||||||
| Exchanges payable |
— | (10,094 | ) | — | |||||||||||
| Long-term debt |
— | — | 215 | ||||||||||||
| Deferred taxes—noncurrent |
(47,040 | ) | — | — | — | ||||||||||
| Total liabilities assumed |
(47,040 | ) | (11,602 | ) | (2,788 | ) | 268 | ||||||||
| Net assets acquired |
$ | 87,000 | $ | 498,571 | $ | 258,676 | $ | 16,700 | |||||||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
The assets acquired and purchase price allocation of acquisitions subsequent to August 31, 2004 were as follows:
| Texas Chalk and Madison Systems November 2004 |
HPL January 2005 |
HOLP acquisitions (aggregated) September 1, 2004 to May 31, 2005 |
||||||||||
| Cash and equivalents |
$ | — | $ | 191 | $ | 5 | ||||||
| Accounts receivable |
— | 370,378 | 429 | |||||||||
| Inventory |
— | 130,280 | 243 | |||||||||
| Other current assets |
— | 23,567 | 184 | |||||||||
| Investment in unconsolidated affiliate |
— | 32,940 | — | |||||||||
| Price risk management assets |
— | 28,638 | — | |||||||||
| Property, plant and equipment |
66,667 | 824,386 | 11,074 | |||||||||
| Intangibles |
— | 3,740 | ||||||||||
| Goodwill |
— | — | 2,439 | |||||||||
| Total assets acquired |
66,667 | 1,410,380 | 18,114 | |||||||||
| Accounts payable |
(525 | ) | (313,469 | ) | (233 | ) | ||||||
| Accrued expenses |
(1,510 | ) | (36,077 | ) | (352 | ) | ||||||
| Other current liabilities |
— | (13,247 | ) | |||||||||
| Other liabilities |
— | (6,710 | ) | |||||||||
| Deposits from vendor |
— | — | ||||||||||
| Price risk management liabilities |
— | (28,638 | ) | |||||||||
| Exchanges payable |
— | — | ||||||||||
| Long-term debt |
— | (1,149 | ) | |||||||||
| Minority interests |
— | (15,129 | ) | — | ||||||||
| Total liabilities assumed |
(2,035 | ) | (413,270 | ) | (1,734 | ) | ||||||
| Net assets acquired |
$ | 64,632 | $ | 997,110 | $ | 16,380 | ||||||
Each of these acquisitions was accounted for as a business combination using the purchase method of accounting in accordance with SFAS 141, and each purchase price has been allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition. The results of operations for these acquisitions are included in the Consolidated Statements of Operations from the date of the respective acquisition.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
5. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:
Long-term debt of ETP and its operating subsidiaries consists of the following on a consolidated basis:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||||
| HOLP Notes |
||||||||
| 1996 8.55% Senior Secured Notes |
$ | 84,000 | $ | — | ||||
| 1997 Medium Term Note Program: |
— | |||||||
| 7.17% Series A Senior Secured Notes |
12,000 | — | ||||||
| 7.26% Series B Senior Secured Notes |
18,000 | — | ||||||
| 6.50% Series C Senior Secured Notes |
1,786 | — | ||||||
| 2000 and 2001 Senior Secured Promissory Notes: |
— | — | ||||||
| 8.47% Series A Senior Secured Notes |
9,600 | — | ||||||
| 8.55% Series B Senior Secured Notes |
27,429 | — | ||||||
| 8.59% Series C Senior Secured Notes |
27,000 | — | ||||||
| 8.67% Series D Senior Secured Notes |
58,000 | — | ||||||
| 8.75% Series E Senior Secured Notes |
7,000 | — | ||||||
| 8.87% Series F Senior Secured Notes |
40,000 | — | ||||||
| 7.21% Series G Senior Secured Notes |
15,200 | — | ||||||
| 7.89% Series H Senior Secured Notes |
8,000 | — | ||||||
| 7.99% Series I Senior Secured Notes |
16,000 | — | ||||||
| ETC OLP Term Loan Facility |
725,000 | 226,000 | ||||||
| HOLP Senior Revolving Acquisition Facility |
23,000 | — | ||||||
| HOLP Long term portion of the Senior Revolving Working Capital Facility |
10,000 | — | ||||||
| HOLP Notes payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010 |
18,218 | — | ||||||
| Other |
2,159 | — | ||||||
| Current maturities of long-term debt |
(31,234 | ) | (30,000 | ) | ||||
| $ | 1,071,158 | $ | 196,000 | |||||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Maturities of HOLP’s Senior Secured Notes, the Medium Term Note Program and the Senior Secured Promissory Notes (the HOLP Notes) are as follows:
| 1996 8.55% Senior Secured Notes: | ||
| mature at the rate of $12,000 on June 30 in each of the years 2002 to and including 2011. Interest is paid semi-annually. | ||
| 1997 Medium Term Note Program: | ||
| Series A Notes: |
mature at the rate of $2,400 on November 19 in each of the years 2005 to and including 2009. Interest is paid semi-annually. | |
| Series B Notes: |
mature at the rate of $2,000 on November 19 in each of the years 2003 to and including 2012. Interest is paid semi-annually. | |
| Series C Notes: |
mature at the rate of $714 on March 13 in each of the years 2000 to and including 2003, $357 on March 13, 2004, $1,073 on March 13, 2005, and $357 in each of the years 2006 and 2007. Interest is paid semi-annually. | |
| 2000 and 2001 Senior Secured Promissory Notes: | ||
| Series A Notes: |
mature at the rate of $3,200 on August 15 in each of the years 2003 to and including 2007. Interest is paid quarterly. | |
| Series B Notes: |
mature at the rate of $4,571 on August 15 in each of the years 2004 to and including 2010. Interest is paid quarterly. | |
| Series C Notes: |
mature at the rate of $5,750 on August 15 in each of the years 2006 to and including 2007, $4,000 on August 15, 2008 and $5,750 on August 15, 2009 to and including 2010. Interest is paid quarterly. | |
| Series D Notes: |
mature at the rate of $12,450 on August 15 in each of the years 2008 and 2009, $7,700 on August 15, 2010, $12,450 on August 15, 2011 and $12,950 on August 15, 2012. Interest is paid quarterly. | |
| Series E Notes: |
mature at the rate of $1,000 on August 15 in each of the years 2009 to and including 2015. Interest is paid quarterly. | |
| Series F Notes: |
mature at the rate of $3,636 on August 15 in each of the years 2010 to and including 2020. Interest is paid quarterly. | |
| Series G Notes: |
mature at the rate of $3,800 on May 15 in each of the years 2004 to and including 2008. Interest is paid quarterly. $7.5 million of these notes were retired during the fiscal year ended August 31, 2003. | |
| Series H Notes: |
mature at the rate of $727 on May 15 in each of the years 2006 to and including 2016. Interest is paid quarterly. $19.5 million of these notes were retired during the fiscal year ended August 31, 2003. | |
| Series I Notes: |
mature in one payment of $16,000 on May 15, 2013. Interest is paid quarterly. | |
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Index to Financial Statements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure HOLP’s Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, HOLP is required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of August 31, 2004 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that HOLP pay the additional 1% interest.
Effective August 31, 2004, ETC OLP entered into the Third Amendment to the Second Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $725,000 Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 4.45% as of August 31, 2004. The ETC OLP Term Loan Facility was secured by substantially all of the ETC OLP’s assets. As of August 31, 2004 and 2003, the Term Loan Facility had a balance of $725,000 and $226,000, respectively. In January 2005 the balance of the ETC OLP Term Loan Facility was paid in full.
A $225,000 Revolving Credit Facility was available through January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The maximum commitment fee payable on the unused portion of the ETC OLP facility was 0.50%. The facility was fully secured by substantially all of ETC OLP’s assets. As of August 31, 2004, there were no amounts outstanding under the ETC OLP Revolving Credit Facility, and $4,650 in letters of credit outstanding which reduce the amount available for borrowing under the ETC OLP Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40,000. In January 2005, the balance of the ETC OLP Credit Facility was paid in full.
Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $75,000 HOLP Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the HOLP Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.2038% for the amount outstanding at August 31, 2004. The maximum commitment fee payable on the unused portion of the HOLP facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Working Capital Facility. As of August 31, 2004, the HOLP Senior Revolving Working Capital Facility had a balance outstanding of $24,550, of which $10,000 was long-term and $14,550 was short-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Working Capital Facility. Letter of Credit Exposure plus the HOLP Working Capital Loan cannot exceed the $75,000 maximum HOLP Working Capital Facility. HOLP had outstanding Letters of Credit of $1,002 at August 31, 2004.
A $75,000 HOLP Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the HOLP Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.2038% for the amount outstanding at August 31, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Acquisition Facility. As of August 31, 2004, the HOLP Senior Revolving Acquisition Facility had a balance outstanding of $23,000.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
The agreements for each of the HOLP Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and HOLP and ETC OLP’s (collectively the Operating Partnerships) bank credit facilities contain customary restrictive covenants applicable to the Operating Partnerships, including limitations on substantial disposition of assets, changes in ownership of the Operating Partnerships, the level of additional indebtedness and creation of liens. These covenants require the Operating Partnerships to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the Operating Partnership’s bank credit facilities and the HOLP Note Agreements) of not more than, 4.75 to 1.0 for HOLP and 4.75 to 1.0 during the 365-day period following the funding of the purchase price of the ET Fuel System and to 4.0 to 1.0 during any period other than the 365-day period following the funding of the purchase price of the ET Fuel System for ETC OLP and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1 for HOLP and 2.75 to 1 for ETC OLP. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the operating partnership’s bank credit facilities and the HOLP Note Agreements, Consolidated EBITDA is based upon the Operating Partnerships’ EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
Failure to comply with the various restrictive and affirmative covenants of the Operating Partnerships’ bank credit facilities and the HOLP Note Agreements could negatively impact the Operating Partnerships’ ability to incur additional debt and/or ETP’s ability to pay distributions. The Operating Partnerships are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the HOLP Senior Secured Notes, HOLP Medium Term Note Program, HOLP Senior Secured Promissory Notes, and the Operating Partnership’s bank credit facilities as of August 31, 2004.
Future maturities of long-term debt for each of the next five fiscal years and thereafter are $31,235 in 2005; $39,355 in 2006; $72,009 in 2007; $770,756 in 2008; $42,909 in 2009, and $146,129 thereafter.
Debt transactions subsequent to August 31, 2004
On January 18, 2005, in a Rule 144A private placement offering, ETP issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. ETP recorded debt issue costs of $6,413 and a discount of $2,265 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities described above. As a result of the repayment, ETP wrote off $7,996 in deferred financing costs and accounted for the write-off as loss on extinguishment of debt. On July 29, 2005, ETP
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
completed a registered exchange offer to exchange newly issued 5.95% Senior Notes due 2015 which have been registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old Notes). The sole purpose of the exchange offer was to fulfill the obligations of ETP under the registration rights agreement entered into in connection with the sale by ETP of the Old Notes. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes.
On July 29, 2005 ETP completed an offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, whereby ETP issued $400,000 in aggregate principal amount of 5.65% Senior Unsecured Notes due 2012. ETP’s Senior Notes due 2012, and ETP’s 5.95% senior notes due 2015, are fully and unconditionally guaranteed by ETC OLP and its subsidiaries.
ETC OLP and its designated subsidiaries act as the guarantor of the debt obligations for the ETP Senior Unsecured Notes issued on January 18, 2005 and the ETP Revolving Credit Facility. If ETP were to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. ETP’s Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured debt.
On January 26, 2005, the Partnership borrowed $200,000 under a Senior Secured Term Facility with Goldman Sachs Credit Partners L.P, secured by the Partnership’s investment in ETP. The interest rate was based on either a Eurodollar rate plus 1.25% per annum, or a prime rate plus 0.250% per annum. Of the proceeds, $174,624 was used to finance the acquisition of working inventory of natural gas from HPL. The remaining proceeds of approximately $25,000 were re-paid in February 2005. The loan was paid in full on April 14, 2005.
On June 16, 2005, the Partnership entered into a $600,000 Senior Secured Loan Agreement with Goldman Sachs Credit Partners L.P., as administrative agent, and a syndicate of financial institutions that matures on June 16, 2008. Loans in an amount of $600,000 were borrowed and loans repaid under the term loan agreement may not be re-borrowed. The loans are secured by the Partnership’s ETP Common Units and general partner interest in ETP. The Partnership’s Senior Secured Loan Agreement requires that, on the last day of the specified fiscal quarter, the ratio of its Consolidated Funded Debt (as defined in the term loan agreement) to the Partnership’s Consolidated EBITDA (as defined in the term loan agreement) for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. The Partnership’s term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Partnership’s term loan agreement) to its Consolidated Interest Expense (as defined in the Partnership’s term loan agreement) must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008.
Also on January 18, 2005, ETP entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under ETP’s Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. Effective June 2, 2005, ETP increased the unsecured Revolving Credit Facility from $700,000 to $800,000. The maximum commitment fee payable on the unused portion of the facility is 0.30%. ETP’s Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 and a daily rate based on the London market.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
6. DISCONTINUED OPERATIONS:
On April 14, 2005, ETC OLP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191,606, including certain adjustments as provided for in the purchase and sale agreement. The sale of the Elk City System has been accounted for as discontinued operations. The Consolidated Statements of Operations for the year ended August 31, 2004, and the eleven month period ended August 31, 2003 have been restated to present (as net amounts) the results of discontinued operations. Selected operating results for these discontinued operations are presented in the following table:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||||
| Revenues |
$ | 135,297 | $ | 92,441 | ||||
| Cost and expenses |
(129,134 | ) | (86,447 | ) | ||||
| Net Income |
$ | 6,163 | $ | 5,994 | ||||
7. INCOME TAXES:
The components of the federal and state income tax provision (benefit) of the Partnership’s taxable subsidiaries for the year ended August 31, 2004 and the eleven months ended August 31, 2003, is summarized as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||||
| Current provision: |
||||||||
| Federal |
$ | 6,505 | $ | 5,548 | ||||
| State |
831 | — | ||||||
| Total |
7,336 | 5,548 | ||||||
| Deferred benefit: |
||||||||
| Federal |
(4,367 | ) | (1,116 | ) | ||||
| State |
(177 | ) | — | |||||
| Total |
(4,544 | ) | (1,116 | ) | ||||
| Total tax provision |
$ | 2,792 | $ | 4,432 | ||||
The effective tax rate is different than the statutory rate due primarily from income attributable to the Partnership earnings not subject to federal and state income taxes. The difference between the statutory rate and the effective rate is summarized as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||
| Federal income tax rate |
35.00 | % | 35.00 | % | ||
| State income tax rate net of federal benefit |
3.96 | % | — | |||
| Increase (decrease) as a result of: |
||||||
| Partnership earnings not subject to tax |
(34.40 | )% | (25.08 | )% | ||
| Corporate subsidiary earnings not subject to state tax |
(3.56 | )% | — | |||
| Effective tax rate |
1.0 | % | 9.92 | % |
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred tax liability were as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
||||||
| Property, plant and equipment |
$ | 215,491 | 55,736 | ||||
| Other |
1,235 | (351 | ) | ||||
| $ | 216,726 | $ | 55,385 | ||||
8. MAJOR CUSTOMERS AND SUPPLIERS:
ETP had gross sales as a percentage of total revenues to nonaffiliated major customers as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||
| Midstream Segment: |
||||||
| BP Energy Company |
11.6 | % | 1.5 | % | ||
| Houston Pipeline Company |
11.2 | % | 11.1 | % | ||
| Dow Hydrocarbon and Resources, Inc. |
10.7 | % | 18.6 | % |
ETP’s major customers are in the midstream segment. ETP’s natural gas operations have a concentration of customers in natural gas transmission, distribution and marketing, as well as industrial end-users while its NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact ETP’s overall exposure to credit risk, either positively or negatively. As of August 31, 2004, ETP had a receivable from BP Energy Company that was approximately 15% of the Partnership’s total net accounts receivable. However, management believes that ETP’s portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. No single customer accounts for 10% or more of ETP’s transportation or propane revenues.
The Partnership had gross segment purchases as a percentage of total segment purchases from major suppliers as follows:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||
| Midstream Segment: |
||||||
| Unaffiliated |
||||||
| BP Energy Company |
11.0 | % | 2.1 | % | ||
| Burlington Resources |
6.1 | % | 10.1 | % | ||
| Propane Segments(a) |
||||||
| Unaffiliated |
||||||
| Enterprise |
22.5 | % | — | |||
| Dynegy |
21.8 | % | — | |||
| Affiliated |
||||||
| M.P. Oils, Ltd. |
21.0 | % | — |
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
| (a) | Purchases from major suppliers in the propane segment represent amounts purchased from January 20, 2004 through August 31, 2004. If the Energy Transfer transactions had occurred at the beginning of the periods presented, the percentages purchased from Enterprise, Dynegy and MP Oils Ltd. would have been 24.9%, 18.8% and 19%, respectively, for the year ended August 31, 2004, and 28.6%, 13.5% and 19% for the period ended August 31, 2003, respectively. |
These concentrations of suppliers may impact ETP’s overall exposure to credit risk, either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable ETP to purchase all of its supply needs at market prices without a material disruption of operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of propane will be readily available in the future, we expect a sufficient supply to continue to be available.
9. COMMITMENTS AND CONTINGENCIES:
Commitments
Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these leases totaled approximately $4,283 for the year ended August 31, 2004, and has been included in operating expenses in the accompanying statements of operations. Fiscal year future minimum lease commitments for such leases are $4,794 in 2005; $3,048 in 2006; $2,104 in 2007; $1,647 in 2008; $1,216 in 2009 and $628 thereafter. Rental expense for the eleven months ended August 31, 2003 related to operating leases was $881 and has been included in operating expenses in the accompanying statements of operations.
ETP has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery up to 20 million British thermal units per day (MMBtu/d). Long-term contracts total require delivery of up to 156 MMBtu/d. The long-term contracts run through July 2013.
In connection with the acquisition of the ET Fuel System in June of 2004, ETP entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. ETP also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005, ETP was entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, ETP recognized an additional $14,716 in fees during the nine months ended May 31, 2005. TXU Shipper has notified ETP that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.
ETP has signed long-term agreements with several parties committing firm transportation volumes into the East Texas Pipeline which is part of the East Texas Pipeline System. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational and expires in June 2012.
In connection with the HPL acquisition in January 2005, ETP acquired a sales agreement whereby ETP is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 1.8 million MMBtu, 9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. ETP also assumed a contract with a service provider which obligates ETP to obtain certain compressor, measurement and other services through 2007 with monthly payments of approximately $1,700.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
ETP in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.
ETP has entered into several propane purchase and supply commitments with varying terms as to quantities and prices, which expire at various dates through March 2006.
Litigation
ETP’s midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.
Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or are named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. ETP maintains liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.
Of the pending or threatened matters in which the ETP or its subsidiaries are a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P., and they were dismissed from the litigation. On October 21, 2004, HOLP announced that it received a favorable jury verdict with respect to the SCANA litigation. The jury found in favor of HOLP on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. SCANA has appealed the jury’s decision, and currently, the parties are involved in the appeal of a number of post-trial motions. ETP cannot predict whether the final judgment will affirm the jury verdict without any modification. Because of the uncertainty of the final determination and the net amount of funds ETP could receive, the Partnership cannot predict whether it will receive any of the damages award ETP may receive. The Partnership is entitled to a portion of that award only to the extent that ETP distributes any of the award to its Common Unitholders. As a result, management cannot yet predict whether the Partnership will receive any of the damages awarded by this verdict.
At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (B of A) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum
F-58
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
ETP or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, ETP accrues the related deductible. As of August 31, 2004, an accrual of $930 was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheet. An accrual of $112 was recorded as of August 31, 2003.
Environmental
ETP’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although ETP believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, ETP has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has ETP’s operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in the Partnership’s August 31, 2004 balance sheet. Based on information currently available to the Partnership, such projects are not expected to have a material adverse effect on the Partnership’s financial condition or results of operations.
In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the EPA) regarding potential contribution to a widespread groundwater
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on the Partnership’s financial condition or results of operations.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. As of August 31, 2004 and 2003, an accrual of $473 and $633, respectively, was recorded in the Partnership’s balance sheet to cover any material environmental liabilities that were not covered by the environmental indemnifications.
10. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
ETP is exposed to market risks related to the volatility of natural gas and NGL prices. To reduce the impact of this price volatility, ETP primarily uses derivative commodity instruments (futures and swaps) to manage its exposures to fluctuations in margins. The fair value of all price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income until the settlement month. The amount on the balance sheet relating to price risk management assets and liabilities in accumulated other comprehensive income will be reclassified into earnings over the next twelve months. When the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in costs of products sold in the statement of operations. Unrealized gains or losses on price risk management assets and liabilities that do not meet the requirements for hedge accounting are recognized in costs of products sold in the statement of operations. ETP’s price risk management assets and liabilities were as follows:
| As of August 31, 2004 |
Commodity |
Notional Volume |
Maturity |
Fair Value |
||||||
| (MMBtu) | ||||||||||
| Basis Swaps IFERC/Nymex |
Gas | 54,472,500 | 2004-2005 | $ | 1,451 | |||||
| Basis Swaps IFERC/Nymex |
Gas | 62,767,500 | 2004-2005 | 592 | ||||||
| 2,043 | ||||||||||
| Swing Swaps IFERC |
Gas | 119,495,000 | 2004-2005 | 704 | ||||||
| Swing Swaps IFERC |
Gas | 45,265,000 | 2004-2005 | (399 | ) | |||||
| Swing Swaps IFERC |
Gas | 76,720,000 | 2006-2008 | — | ||||||
| $ | 305 | |||||||||
| Futures Nymex |
Gas | 10,057,500 | 2004-2005 | $ | (1,311 | ) | ||||
| Futures Nymex |
Gas | 12,677,500 | 2004-2005 | 2,941 | ||||||
| 1,630 | ||||||||||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
| As of August 31, 2004 |
Commodity |
Notional Volume |
Maturity |
Fair Value |
||||||
| Barrels | ||||||||||
| NGL Swaps |
Condensate, Propane, Ethane |
250,000 | 2004-2005 | $ | (86 | ) | ||||
| August 31, 2003 |
MMBTU |
|||||||||
| Basis Swaps IFERC/Nymex |
Gas | 24,330,000 | 2003-2004 | $ | 612 | |||||
| Basis Swaps IFERC/Nymex |
Gas | 10,165,000 | 2003-2004 | (184 | ) | |||||
| $ | 428 | |||||||||
| Futures Nymex |
Gas | 3,115,000 | 2003-2004 | $ | (56 | ) | ||||
| Futures Nymex |
Gas | 5,970,000 | 2003-2004 | 540 | ||||||
| $ | 484 | |||||||||
Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions.
Interest Rate Risk
ETP was exposed to market risk for changes in interest rates related to its bank credit facilities of ETC OLP. An interest rate swap agreement was used to manage a portion of the exposure related to ETC OLP’s Term Loan Facility to changing interest rates by converting floating rate debt to fixed-rate debt. On October 9, 2002, ETC OLP entered into an interest rate swap agreement to manage its exposure to changes in interest rates. The interest rate swap had a notional value of $75,000 and matures on October 9, 2005. Under the terms of the interest rate swap agreement, the ETP will pay a fixed rate of 2.76% and received three-month LIBOR with quarterly settlement commencing on January 9, 2003. The value of the interest rate swap was marked to market and recorded in interest expense. The value of the interest rate swap at August 31, 2004 and 2003, was a liability of $539 and $807 respectively, and was recorded as a component of price risk management liabilities on the Partnership’s consolidated financial statements.
The following represents gain (loss) on derivative activity:
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 |
|||||||
| Unrealized gain recognized in cost of products sold related to ETP’s derivative activity |
$ | 2,919 | $ | 889 | ||||
| Realized gain (loss) included in cost of products sold |
$ | 22,314 | $ | (2,411 | ) | |||
| Unrealized gain on interest rate swap included in interest expense |
$ | 267 | $ | — | ||||
| Realized loss on interest rate swap included in interest expense |
$ | (1,239 | ) | $ | (312 | ) | ||
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
11. PARTNERS’ CAPITAL:
The ETE partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners in pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, first, such net losses shall be allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the partnership agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
As certain conditions were met, ownership percentages changed. In January 2004, as a result of the Energy Transfer Transactions, certain conditions were met, which changed the relative ownership percentages of the Partnership.
On October 1, 2002, the Partnership received a cash contribution from LE GP, LLC of $1,579 in exchange for a 1% general partner interest in the Partnership. Also on October 1, 2002, the partnership received cash of $108,620 and assets of $31,017 from various investors in exchange for 156,315,788 limited partner units representing 99% limited partnership interests in the partnership.
On January 19, 2004, the Partnership issued 1,042,596 limited partner units valued at $1,743 to a group of limited partners in exchange for their contribution of various subsidiary partnership interests and an office building and related contents. These assets and subsidiary partnership interests were subsequently contributed to ETP in exchange for an increased limited partner interest in ETP.
The Partnership paid distributions of $266,277 and $4,820 for fiscal year 2004 and 2003, respectively.
12. ETP’S QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:
The partnership agreement of ETP requires that ETP will distribute all of its Available Cash to its Unitholders and its general partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s partnership agreement.
Distributions by ETP in an amount equal to 100% of Available Cash will generally be made 98% to the Common, Class D, and Class E Unitholders and 2% to its general partner, ETP GP, subject to the payment of incentive distributions to ETP GP to the extent that certain target levels of cash distributions are achieved.
On April 14, 2004, ETP paid a quarterly distribution of $0.35 per unit, or $1.40 per unit annually, to the Unitholders of record at the close of business on April 2, 2004. On July 15, 2004, ETP paid a quarterly
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
distribution of $0.375 per unit, or $1.50 per unit annually, to Unitholders of record at the close of business on July 2, 2004. On October 15, 2004, ETP paid a quarterly distribution for the fourth quarter ended August 31, 2004 of $0.4125 per unit, or $1.65 per unit annually, to Unitholders of record at the close of business on October 7, 2004. On January 14, 2005, ETP paid a quarterly distribution of $0.4375 per unit, or $1.75 per unit annually, to Unitholders of record at the close of business on January 5, 2005. On April 14, 2005, ETP paid a quarterly distribution of $0.4625 per unit, or $1.85 per unit annually. On July 15, 2005, ETP paid a quarterly distribution of $0.4875 per unit, or $1.95 per unit annually. In addition to these quarterly distributions, ETP GP received quarterly distributions for its general partner interest in ETP, and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit. The total amount of distributions paid or declared relating to the quarters in the period from January 20, 2004 through August 31, 2004 on Common Units, the Class D Units, the Class E, its general partner interests and the Incentive Distribution Rights totaled $89.8 million, $5.4 million, $9.3 million, $2.3 million and $6.9 million, respectively. The total amount of distributions paid as of July 15, 2005 on ETP’s Common Units, the Class E Units, its general partner interests and the Incentive Distribution Rights totaled $136,992, $9,363, $3,508, and $25,514, respectively. All such distributions were made from Available Cash from Operating Surplus. ETE receives distributions from ETP GP to the extent of its ownership percentage in ETP GP and from ETP on its Common Unit ownership in ETP.
ETP makes distributions of available cash from operating surplus for any quarter in the following manner:
| • | First, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to its general partner, until each Common Unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”); |
| • | Second, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to its general partner, until each Common Unit has received $0.275 per unit for such quarter (the “first target distribution”); |
| • | Third, 85% to all Common and Class E Unitholders, in accordance with their percentage interests, 13% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner, until each Common Unit has received at least $0.3175 per unit for such quarter (the “second target distribution”); |
| • | Fourth, 75% to all Common and Class E Unitholders, in accordance with their percentage interests, 23% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner, until each Common Unit has received at least $0.4125 per unit for such quarter; (the “third target distribution”); and |
| • | Fifth, thereafter, 50% to all Common and Class E Unitholders, in accordance with their percentage interests, 48% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner. |
Notwithstanding the foregoing, any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E unit may not exceed $2.82 per year.
13. RETIREMENT BENEFITS:
ETP also sponsors a defined contribution profit sharing and 401(k) savings plan, which covers virtually all employees subject to service period requirements. Profit sharing contributions are made to the plan at the discretion of the Board of Directors and are allocated to eligible employees as of the last day of the plan year. Employer matching contributions are calculated using a discretionary formula based on employee contributions. ETP made matching contributions of $1,539 to the 401(k) savings plan for the year ended August 31, 2004. No matching contributions were made during the eleven months ended August 31, 2003.
F-63
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
14. RELATED PARTY TRANSACTIONS:
Included in midstream and transportation revenues is revenue from affiliates of $17 for the year ended August 31, 2004 and $709 for the eleven months ended August 31, 2003. Accounts payable to related companies as of August 31, 2004 includes approximately $1,400 payable to unconsolidated affiliates for purchases of natural gas and $0 at August 31, 2003.
ETP’s natural gas midstream operations secure compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the ETG Entities. ETP’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of ETP’s General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. During fiscal year 2004, payments totaling $279 were made to the ETG Entities for compression services provided to and utilized in ETP’s natural gas midstream operations and none during the eleven months ended August 31, 2003.
One of ETP’s natural gas midstream subsidiaries owns a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by one of the General Partner’s directors. ETP is the operator of the Dorado System. At August 31, 2004 and 2003, there was a balance of $248 owing to ETP by a director of ETP LLC for services ETP provided as operator. This balance was paid in full subsequent to August 31, 2004.
Prior to the Oasis Pipeline stock redemption and the contribution of ET Company I to ETC, ETC had purchases and sales of natural gas with Oasis Pipeline and ET Company I in the normal course of business. The following table summarizes these transactions:
| October 1, 2002 (Inception) Through December 21, 2002 | |||
| Sales of natural gas to affiliated companies |
$ | 4,488 | |
| Purchases of natural gas from affiliated companies |
$ | 3,989 | |
| Transportation expenses |
$ | 922 | |
Prior to the Energy Transfer Transactions, ET GP, LLC, the general partner of Holdings had a general and administrative services contract to act as an advisor and provide certain general and administrative services to ETE and its affiliates. The general and administrative services that ET GP, LLC provides ETP under this contract include:
| • | General oversight and direction of engineering, accounting, legal and other professional and operational services required for the support, maintenance and operation of the assets used in the Midstream operations, and |
| • | The administration, maintenance and compliance with contractual and regulatory requirements. |
In exchange for these services, ETE and its affiliates are required to pay ET GP, LLC a $500 annual fee payable quarterly and pro-rated for any portion of a calendar year. Pursuant to this contract, ETE and its affiliates were also required to reimburse ET GP, LLC for expenses associated with formation of ETE and its affiliates and
F-64
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
are required to indemnify ET GP, LLC, its affiliates, officers and employees for liabilities associated with the actions of ET GP, LLC, its affiliates, officers, and employees. The agreement expressly provides that the fee for the services cannot be paid from funds received by ETP, but only from the Partnership’s funds.
15. SUMMERIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:
ETP’s Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee the Partnership’s Revolving Credit Facility and Senior Notes. Following are condensed consolidating financial information of the Partnership, the Issuer (ETP), Guarantor Subsidiaries, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The condensed consolidating financial information is prepared on the equity method and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.
F-65
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
CONDENSED CONSOLIDATING BALANCE SHEET
As of August 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated | ||||||||||||||
| ASSETS |
|||||||||||||||||||
| CURRENT ASSETS: |
|||||||||||||||||||
| Cash and cash equivalents |
$ | 1,101 | $ | 9,506 | $ | 52,054 | $ | 20,191 | $ | — | $ | 82,852 | |||||||
| Marketable securities |
— | — | — | 2,464 | — | 2,464 | |||||||||||||
| Accounts receivable, net of allowance for doubtful accounts |
— | — | 206,023 | 45,323 | — | 251,346 | |||||||||||||
| Other current assets |
2,856 | 2,465 | 91,005 | 57,486 | (8,606 | ) | 145,206 | ||||||||||||
| Total current assets |
3,957 | 11,971 | 349,082 | 125,464 | (8,606 | ) | 481,868 | ||||||||||||
| PROPERTY, PLANT AND EQUIPMENT, net |
— | — | 926,821 | 492,082 | 496,371 | 1,915,274 | |||||||||||||
| INVESTMENT IN AFFILIATES |
364,480 | 989,834 | 7,593 | 182,167 | (1,536,064 | ) | 8,010 | ||||||||||||
| GOODWILL |
— | — | 23,736 | 325,025 | — | 348,761 | |||||||||||||
| INTANGIBLES AND OTHER ASSETS, net |
— | — | 9,610 | 101,668 | — | 111,278 | |||||||||||||
| LONG-TERM AFFILIATED RECEIVABLE |
— | — | 95,000 | — | (95,000 | ) | — | ||||||||||||
| Total assets |
$ | 368,437 | $ | 1,001,805 | $ | 1,411,842 | $ | 1,226,406 | $ | (1,143,299 | ) | $ | 2,865,191 | ||||||
| LIABILITIES AND PARTNERS’ CAPITAL |
|||||||||||||||||||
| CURRENT LIABILITIES: |
|||||||||||||||||||
| Working capital facility |
$ | — | $ | — | $ | — | $ | 14,550 | $ | — | $ | 14,550 | |||||||
| Accounts payable |
— | 715 | 197,897 | 37,019 | — | 235,631 | |||||||||||||
| Other current liabilities |
112 | 3,974 | 62,666 | 65,356 | (8,606 | ) | 123,502 | ||||||||||||
| Current maturities of long-term debt |
— | — | — | 31,234 | — | 31,234 | |||||||||||||
| Total current liabilities |
112 | 4,689 | 260,563 | 148,159 | (8,606 | ) | 404,917 | ||||||||||||
| LONG-TERM DEBT, less current maturities |
— | — | 725,000 | 346,158 | — | 1,071,158 | |||||||||||||
| LONG-TERM AFFILIATED PAYABLE |
— | 95,000 | — | — | (95,000 | ) | — | ||||||||||||
| DEFERRED TAXES |
— | — | 54,436 | 55,460 | 106,830 | 216,726 | |||||||||||||
| MINORITY INTERESTS |
— | — | 1,475 | 801,745 | 803,220 | ||||||||||||||
| OTHER NONCURRENT LIABILITIES |
— | — | 845 | — | — | 845 | |||||||||||||
| 112 | 99,689 | 1,040,844 | 551,252 | 804,969 | 2,496,866 | ||||||||||||||
| COMMITMENTS AND CONTINGENCIES |
|||||||||||||||||||
| PARTNERS’ CAPITAL |
368,325 | 902,116 | 370,998 | 675,154 | (1,948,268 | ) | 368,325 | ||||||||||||
| Total liabilities and partners’ capital |
$ | 368,437 | $ | 1,001,805 | $ | 1,411,842 | $ | 1,226,406 | $ | (1,143,299 | ) | $ | 2,865,191 | ||||||
F-66
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the year ended August 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated |
|||||||||||||||||||
| REVENUES: |
||||||||||||||||||||||||
| Midstream and transportation |
$ | — | $ | — | $ | 1,966,803 | $ | — | $ | — | $ | 1,966,803 | ||||||||||||
| Propane |
— | — | — | 342,523 | — | 342,523 | ||||||||||||||||||
| Other |
167 | 20 | — | 37,611 | (167 | ) | 37,631 | |||||||||||||||||
| Total revenue |
167 | 20 | 1,966,803 | 380,134 | (167 | ) | 2,346,957 | |||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||
| Cost of products sold |
— | — | 1,771,321 | 210,103 | — | 1,981,424 | ||||||||||||||||||
| Operating expenses |
— | — | 43,112 | 104,262 | — | 147,374 | ||||||||||||||||||
| Depreciation and amortization |
— | — | 17,063 | 31,536 | 7,643 | 56,242 | ||||||||||||||||||
| Selling, general and administrative |
805 | 4,047 | 18,760 | 7,666 | (167 | ) | 31,111 | |||||||||||||||||
| Total costs and expenses |
805 | 4,047 | 1,850,256 | 353,567 | 7,476 | 2,216,151 | ||||||||||||||||||
| OPERATING INCOME (LOSS) |
(638 | ) | (4,027 | ) | 116,547 | 26,567 | (7,643 | ) | 130,806 | |||||||||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||||||||||||||
| Interest expense |
— | (2,464 | ) | (20,547 | ) | (20,703 | ) | 2,497 | (41,217 | ) | ||||||||||||||
| Equity in earnings (losses) of affiliates |
55,602 | 105,884 | 499 | 7,557 | (169,179 | ) | 363 | |||||||||||||||||
| Loss on disposal of assets |
— | — | (7 | ) | (999 | ) | — | (1,006 | ) | |||||||||||||||
| Gain on Energy Transfer Transactions |
395,253 | — | — | — | — | 395,253 | ||||||||||||||||||
| Other, net |
— | — | 3,086 | (73 | ) | (2,497 | ) | 516 | ||||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE |
450,217 | 99,393 | 99,578 | 12,349 | (176,822 | ) | 484,715 | |||||||||||||||||
| Minority interests in income from continuing operations |
— | — | — | (295 | ) | (34,869 | ) | (35,164 | ) | |||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME EXPENSE |
450,217 | 99,393 | 99,578 | 12,054 | (211,691 | ) | 449,551 | |||||||||||||||||
| Income tax expense |
— | (241 | ) | (1,716 | ) | (2,525 | ) | 1,690 | (2,792 | ) | ||||||||||||||
| INCOME FROM CONTINUING OPERATIONS |
450,217 | 99,152 | 97,862 | 9,529 | (210,001 | ) | 446,759 | |||||||||||||||||
| DISCONTINUED OPERATIONS: |
||||||||||||||||||||||||
| Income from discontinued operations |
— | 6,163 | — | (2,705 | ) | 3,458 | ||||||||||||||||||
| NET INCOME |
$ | 450,217 | $ | 99,152 | $ | 104,025 | $ | 9,529 | $ | (212,706 | ) | $ | 450,217 | |||||||||||
F-67
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the year ended August 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated |
|||||||||||||||||||
| NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES |
$ | (1,316 | ) | $ | (8,112 | ) | $ | 110,163 | $ | 60,750 | $ | (39,387 | ) | $ | 122,098 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||||||
| Cash paid for acquisitions, net of cash acquired |
(30,000 | ) | (191,377 | ) | (498,570 | ) | (16,710 | ) | 113,728 | (622,929 | ) | |||||||||||||
| Capital expenditures |
— | — | (95,191 | ) | (14,497 | ) | — | (109,688 | ) | |||||||||||||||
| Investments in unconsolidated subsidiaries |
(22,231 | ) | (372,982 | ) | (250 | ) | (15,612 | ) | 410,753 | (322 | ) | |||||||||||||
| Proceeds from the sale of assets |
88,906 | — | 105 | 1,003 | (88,906 | ) | 1,108 | |||||||||||||||||
| Net cash used in investing activities |
36,675 | (564,359 | ) | (593,906 | ) | (45,816 | ) | 435,575 | (731,831 | ) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||||||
| Proceeds from borrowings |
— | 101,693 | 830,000 | 64,079 | (101,693 | ) | 894,079 | |||||||||||||||||
| Principal payments on debt |
— | (6,693 | ) | (331,000 | ) | (179,182 | ) | 6,693 | (510,182 | ) | ||||||||||||||
| Advances from (to) affiliates |
— | — | (95,000 | ) | — | 95,000 | — | |||||||||||||||||
| Capital contributions |
— | 22,231 | 292,982 | 95,540 | (410,753 | ) | — | |||||||||||||||||
| Net proceeds from issuance of common units of subsidiary |
— | 528,129 | — | — | — | 528,129 | ||||||||||||||||||
| Distributions to partners |
(266,277 | ) | — | — | — | — | (266,277 | ) | ||||||||||||||||
| Distributions to parent |
230,067 | (23,996 | ) | (206,071 | ) | — | — | — | ||||||||||||||||
| Debt issuance costs |
— | — | (8,236 | ) | — | — | (8,236 | ) | ||||||||||||||||
| Unit distributions |
— | (39,387 | ) | — | — | 39,387 | — | |||||||||||||||||
| Net cash provided by |
(36,210 | ) | 581,977 | 482,675 | (19,563 | ) | (371,366 | ) | 637,513 | |||||||||||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
(851 | ) | 9,506 | (1,068 | ) | (4,629 | ) | 24,822 | 27,780 | |||||||||||||||
| CASH AND CASH EQUIVALENTS, beginning of period |
1,950 | — | 53,122 | 24,822 | (24,822 | ) | 55,072 | |||||||||||||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 1,099 | $ | 9,506 | $ | 52,054 | $ | 20,193 | $ | — | $ | 82,852 | ||||||||||||
F-68
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
16. REPORTABLE SEGMENTS:
The Partnership’s financial statements reflect five reportable segments: ETC OLP’s midstream and transportation operations, HOLP’s retail and domestic wholesale propane operations, the foreign wholesale propane operations of MP Energy Partnership. The operations which focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily at the Southeast Texas System and Elk City Systems, which was sold on April 14, 2005, generate revenue primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through ETP’s pipeline (excluding the transportation pipelines) and gathering systems and the level of natural gas and NGL prices. The transportation operations focus on transporting natural gas through ETP’s Oasis Pipe Line, ET Fuel System and Bossier Pipeline. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas on the pipeline on an interruptible basis.
ETP’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. ETP manages these propane segments separately as each segment involves different distribution, sale, and marketing strategies. Selling, general and administrative expenses are allocated to the midstream and transportation operating segments, however, ETP evaluates the performance of its other operating segments based on operating income exclusive of selling, general, and administrative expenses of $12,517 and $552 for the year ended August 31, 2004 and the eleven months ended August 31, 2003, respectively. Investment in affiliates and equity in earnings (losses) of affiliates relates primarily to ETP’s investment in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd, and is part of the midstream segment. In addition, ETP’s two largest customers’ revenues are included in the midstream segment’s revenues. The following table presents the unaudited financial information by segment for the following periods:
| Year Ended August 31, |
Eleven Months August 31, 2003 | ||||
| Volumes |
|||||
| Midstream |
|||||
| Natural gas MMBtu/d |
934,000 | 490,000 | |||
| NGLs bbls/d |
7,000 | 9,000 | |||
| Transportation |
|||||
| Natural gas MMBtu/d |
1,091,000 | 921,000 | |||
| Propane gallons |
|||||
| (in thousands) |
|||||
| Retail |
226,209 | — | |||
| Domestic wholesale |
7,071 | — | |||
| Foreign wholesale |
|||||
| Affiliated |
48,712 | — | |||
| Unaffiliated |
28,648 | — | |||
| Elimination |
(48,712 | ) | — | ||
| Total gallons |
261,928 | — | |||
F-69
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
| Year Ended August 31, |
Eleven Months August 31, 2003 |
|||||||
| Revenues: |
||||||||
| Midstream |
||||||||
| Unaffiliated |
$ | 1,880,647 | $ | 898,377 | ||||
| Affiliated |
17 | 709 | ||||||
| Eliminations |
(27,798 | ) | (9,559 | ) | ||||
| Transportation |
113,938 | 41,500 | ||||||
| Retail propane and related |
349,364 | — | ||||||
| Domestic wholesale propane |
5,358 | — | ||||||
| Foreign wholesale propane |
||||||||
| Affiliated |
21,868 | — | ||||||
| Unaffiliated |
21,987 | — | ||||||
| Eliminations |
(21,868 | ) | — | |||||
| Other |
3,444 | — | ||||||
| Total |
$ | 2,346,957 | $ | 931,027 | ||||
| Cost of sales: |
||||||||
| Midstream |
$ | 1,787,849 | $ | 832,874 | ||||
| Eliminations |
(27,798 | ) | (9,559 | ) | ||||
| Transportation |
11,270 | 2,123 | ||||||
| Retail propane and related |
184,371 | — | ||||||
| Domestic wholesale propane |
4,742 | — | ||||||
| Foreign wholesale propane |
20,129 | — | ||||||
| Other |
861 | — | ||||||
| Total Cost of Sales |
$ | 1,981,424 | $ | 825,438 | ||||
| Operating Income: |
||||||||
| Midstream |
$ | 57,601 | $ | 38,364 | ||||
| Transportation |
51,470 | 17,689 | ||||||
| Retail propane and related |
32,346 | — | ||||||
| Domestic wholesale propane |
(1,737 | ) | — | |||||
| Foreign wholesale propane: |
||||||||
| Affiliated |
408 | — | ||||||
| Unaffiliated |
1,843 | — | ||||||
| Elimination |
(408 | ) | — | |||||
| Other |
1,800 | — | ||||||
| Selling general and administrative expenses not allocated to segments |
(12,517 | ) | (552 | ) | ||||
| Total |
$ | 130,806 | $ | 55,501 | ||||
F-70
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
| Year Ended August 31, |
Eleven Months August 31, 2003 |
|||||||
| Income from discontinued operations, net of income tax expense and minority interests: |
||||||||
| Midstream |
$ | 3,458 | $ | 5,994 | ||||
| Gain (loss) on disposal of assets: |
||||||||
| Midstream |
$ | (6 | ) | $ | — | |||
| Transportation |
(1 | ) | — | |||||
| Retail propane |
(999 | ) | — | |||||
| Total |
$ | (1,006 | ) | $ | — | |||
| Minority interests in income from continuing operations |
||||||||
| Other |
$ | 34,869 | $ | — | ||||
| Foreign wholesale propane |
295 | — | ||||||
| Total |
$ | 35,164 | $ | — | ||||
| Depreciation and amortization: |
||||||||
| Midstream |
$ | 12,451 | $ | 9,056 | ||||
| Transportation |
12,255 | 2,814 | ||||||
| Retail propane |
31,104 | — | ||||||
| Domestic wholesale propane |
417 | — | ||||||
| Foreign wholesale propane |
15 | — | ||||||
| Total |
$ | 56,242 | $ | 11,870 | ||||
| Interest expense: |
||||||||
| Midstream |
$ | 20,841 | $ | 11,924 | ||||
| Transportation |
5,704 | 5,097 | ||||||
| Eliminations |
(5,999 | ) | (4,565 | ) | ||||
| Retail propane |
20,644 | — | ||||||
| Other |
27 | (3 | ) | |||||
| Total |
$ | 41,217 | $ | 12,453 | ||||
| Earnings from equity investments: |
||||||||
| Midstream |
$ | 499 | $ | (149 | ) | |||
| Transportation |
— | 1,572 | ||||||
| Foreign wholesale |
(136 | ) | — | |||||
| Total |
$ | 363 | $ | 1,423 | ||||
| Income tax expense |
||||||||
| Transportation |
$ | 1,716 | $ | 4,432 | ||||
| Other |
1,076 | — | ||||||
| Total |
$ | 2,792 | $ | 4,432 | ||||
F-71
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
| August 31, | ||||||
| 2004 |
2003 | |||||
| Total Assets: |
||||||
| Midstream |
$ | 721,009 | $ | 413,096 | ||
| Transportation |
1,090,983 | 189,007 | ||||
| Retail propane |
956,021 | — | ||||
| Domestic wholesale propane |
12,567 | — | ||||
| Foreign wholesale propane |
10,034 | — | ||||
| Other |
74,577 | 2,037 | ||||
| Total |
$ | 2,865,191 | $ | 604,140 | ||
| Year Ended August 31, 2004 |
Eleven Months Ended August 31, 2003 | |||||
| Additions to property, plant and equipment including acquisitions: |
||||||
| Midstream |
$ | 21,466 | $ | 270,446 | ||
| Transportation |
570,169 | 42,236 | ||||
| Retail propane |
515,284 | — | ||||
| Domestic wholesale propane |
4,492 | — | ||||
| Foreign wholesale propane |
528 | — | ||||
| Corporate |
3,229 | — | ||||
| Total |
$ | 1,115,168 | $ | 312,682 | ||
Corporate assets include vehicles, office equipment and computer software for the use of administrative personnel. These assets are not allocated to segments.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
17. SUPPLEMENTAL INFORMATION:
Following is the balance sheet of the Partnership which is included to provide additional information with respect to the Partnership’s financial position on a stand-alone basis as.
| August 31, | ||||||
| 2004 |
2003 | |||||
| ASSETS |
||||||
| CURRENT ASSETS: |
||||||
| Cash and cash equivalents |
$ | 1,101 | $ | 1,950 | ||
| Accounts receivable |
3 | |||||
| Accounts receivable from related companies |
2,856 | — | ||||
| Prepaid expenses and other |
— | 83 | ||||
| Total current assets |
3,957 | 2,036 | ||||
| INVESTMENT IN AFFILIATES |
364,480 | 181,088 | ||||
| Total assets |
$ | 368,437 | $ | 183,124 | ||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||
| CURRENT LIABILITIES: |
||||||
| Accounts payable to affiliate |
87 | 1 | ||||
| Accrued and other current liabilities |
25 | 492 | ||||
| Total current liabilities |
112 | 493 | ||||
| PARTNERS’ CAPITAL: |
||||||
| General Partner’s capital |
4,053 | 2,118 | ||||
| Limited Partners’ capital |
364,261 | 180,513 | ||||
| Accumulated other comprehensive income |
11 | — | ||||
| Total partners’ capital |
368,325 | 182,631 | ||||
| Total liabilities and partners’ capital |
$ | 368,437 | $ | 183,124 | ||
18. SUBSEQUENT EVENTS:
On January 27, 2005, ETP announced that the Board of Directors of its general partner approved a two-for-one split for each class of ETP’s limited partner units. The split entitled ETP’s Unitholders of record at the close of business on February 28, 2005 to receive one additional ETP Partnership unit for each ETP Partnership unit owned on that date. The distribution of the additional ETP units was made on March 15, 2005. The effect of the split was to double the number of all outstanding ETP Common Units and to reduce by half ETP’s minimum quarterly per unit distribution and the targeted distribution levels. All periods presented and all references to Common Units of ETP have been restated to reflect the effects of the unit split.
In June 2005, ETP completed the sale of 1,640,000 common units to a group of executive managers of ETP, including the President, Vice President and General Counsel, and Vice President-Corporate Development. The units were sold at a price of $31.95 per common unit, which represented a 6% discount to the closing common unit price on June 17, 2005. The transaction was approved by a committee of independent directors of ETP. From the proceeds of approximately $52,000, $30,000 was used to pay outstanding indebtedness on ETP’s revolving credit facility and the remainder was used by ETP for general partnership purposes.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
On July 26, 2005, ETP completed the sale of 3,000,000 common units in a private sale to an institutional investor. The common units were issued pursuant to ETP’s effective shelf registration statement and the proceeds of $105,600 were used by ETP to retire a portion of the outstanding indebtedness on its revolving credit facility and to fund ETP’s recently announced capital expansion projects.
ETP also entered into a long-term agreement in July 2005 with XTO Energy Inc. to transport minimum annual volumes over a ten-year term on pipelines to be constructed by ETP. XTO will also be entitled to transport additional volumes under similar terms. The newly constructed pipelines will consist of 264 miles of 30 inch, 36 inch and 42 inch pipelines while adding approximately 40,000 horsepower of compression. The estimated cost of the pipeline construction project is estimated to be approximately $454,000.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)
| May 31, 2005 |
August 31, 2004 | |||||
| ASSETS |
||||||
| CURRENT ASSETS: |
||||||
| Cash and cash equivalents |
$ | 21,607 | $ | 82,852 | ||
| Marketable securities |
2,658 | 2,464 | ||||
| Accounts receivable, net of allowance for doubtful accounts |
729,261 | 251,346 | ||||
| Accounts receivable from related companies |
665 | 35 | ||||
| Inventories |
261,413 | 53,261 | ||||
| Deposits paid to vendors |
46,441 | 3,023 | ||||
| Exchanges receivable |
19,819 | 8,640 | ||||
| Price risk management assets |
36,307 | 4,615 | ||||
| Prepaid expenses and other |
59,774 | 7,724 | ||||
| Assets held for sale |
— | 67,908 | ||||
| Total current assets |
1,177,945 | 481,868 | ||||
| PROPERTY, PLANT AND EQUIPMENT, net |
2,824,372 | 1,915,274 | ||||
| LONG-TERM PRICE RISK MANAGEMENT ASSETS |
18,824 | — | ||||
| INVESTMENT IN AFFILIATES |
40,857 | 8,010 | ||||
| GOODWILL |
351,320 | 348,761 | ||||
| INTANGIBLES AND OTHER ASSETS, net |
109,037 | 111,278 | ||||
| Total assets |
$ | 4,522,355 | $ | 2,865,191 | ||
| CURRENT LIABILITIES: |
||||||
| Working capital facility |
$ | — | $ | 14,550 | ||
| Accounts payable |
773,904 | 235,631 | ||||
| Accounts payable to related companies |
3,572 | 1,507 | ||||
| Exchanges payable |
20,612 | 12,751 | ||||
| Customer deposits |
24,978 | 11,378 | ||||
| Liabilities from discontinued operations |
— | 20,590 | ||||
| Accrued and other current liabilities |
119,316 | 73,762 | ||||
| Price risk management liabilities |
38,736 | 1,262 | ||||
| Income taxes payable |
1,075 | 2,252 | ||||
| Current maturities of long-term debt |
33,425 | 31,234 | ||||
| Total current liabilities |
1,015,618 | 404,917 | ||||
| LONG-TERM DEBT, less current maturities |
1,570,155 | 1,071,158 | ||||
| LONG-TERM PRICE RISK MANAGEMENT LIABILITIES |
18,861 | — | ||||
| OTHER NON-CURRENT LIABILITIES |
16,660 | 845 | ||||
| DEFERRED TAXES |
219,224 | 216,726 | ||||
| MINORITY INTERESTS |
1,257,862 | 803,220 | ||||
| 4,098,380 | 2,496,866 | |||||
| COMMITMENTS AND CONTINGENCIES |
||||||
| PARTNERS’ CAPITAL: |
||||||
| General partner’s capital |
4,550 | 4,053 | ||||
| Limited partners’ capital (189,437,331 and 194,295,631 limited partner units issued and outstanding as of May 31, 2005 and August 31, 2004, respectively) |
413,464 | 364,261 | ||||
| Accumulated other comprehensive income |
5,961 | 11 | ||||
| Total partners’ capital |
423,975 | 368,325 | ||||
| Total liabilities and partners’ capital |
$ | 4,522,355 | $ | 2,865,191 | ||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except unit and per unit data)
(unaudited)
| Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| REVENUES: |
||||||||
| Midstream and transportation and storage |
$ | 3,673,730 | $ | 1,314,176 | ||||
| Propane |
604,996 | 255,303 | ||||||
| Other |
57,065 | 22,177 | ||||||
| Total revenues |
4,335,791 | 1,591,656 | ||||||
| COSTS AND EXPENSES: |
||||||||
| Cost of products sold |
3,756,078 | 1,345,847 | ||||||
| Operating expenses |
224,122 | 86,622 | ||||||
| Depreciation and amortization |
76,874 | 32,793 | ||||||
| Selling, general and administrative |
43,813 | 19,395 | ||||||
| Total costs and expenses |
4,100,887 | 1,484,657 | ||||||
| OPERATING INCOME |
234,904 | 106,999 | ||||||
| OTHER INCOME (EXPENSE): |
||||||||
| Interest expense |
(66,350 | ) | (25,111 | ) | ||||
| Equity in earnings (losses) of affiliates |
(161 | ) | 506 | |||||
| Loss on disposal of assets |
(665 | ) | (235 | ) | ||||
| Gain on Energy Transfer Transactions |
— | 320,893 | ||||||
| Loss on extinguishment of debt |
(6,550 | ) | — | |||||
| Other, net |
308 | 400 | ||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE |
161,486 | 403,452 | ||||||
| Minority interest in income from continuing operations |
(91,439 | ) | (32,170 | ) | ||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE |
70,047 | 371,282 | ||||||
| Income tax expense |
(5,168 | ) | (3,861 | ) | ||||
| INCOME FROM CONTINUING OPERATIONS |
64,879 | 367,421 | ||||||
| DISCONTINUED OPERATIONS: |
||||||||
| Income from discontinued operations |
5,498 | 4,129 | ||||||
| Gain on sale of discontinued operations, net of income tax expense |
104,562 | — | ||||||
| Minority interest in income from discontinued operations |
(53,060 | ) | (1,776 | ) | ||||
| Total income from discontinued operations |
57,000 | 2,353 | ||||||
| NET INCOME |
$ | 121,879 | $ | 369,774 | ||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS—(Continued)
(in thousands, except unit and per unit data)
(unaudited)
| Nine Months Ended | ||||||
| May 31, 2005 |
May 31, 2004 | |||||
| GENERAL PARTNER’S INTEREST IN NET INCOME |
1,027 | 3,291 | ||||
| LIMITED PARTNERS’ INTEREST IN NET INCOME |
$ | 120,852 | $ | 366,483 | ||
| BASIC NET INCOME PER LIMITED PARTNER UNIT |
||||||
| Limited Partners’ income from continuing operations |
$ | 0.33 | $ | 2.10 | ||
| Limited Partners’ income from discontinued operations |
0.29 | 0.01 | ||||
| NET INCOME PER LIMITED PARTNER UNIT |
$ | 0.62 | $ | 2.11 | ||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
194,171,059 | 174,081,485 | ||||
| DILUTED NET INCOME PER LIMITED PARTNER UNIT |
||||||
| Limited Partners’ income from continuing operations |
$ | 0.27 | $ | 1.50 | ||
| Limited Partners’ income from discontinued operations |
0.23 | 0.01 | ||||
| NET INCOME PER LIMITED PARTNER UNIT |
$ | 0.50 | $ | 1.51 | ||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
242,754,055 | 242,328,183 | ||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
(unaudited)
| Nine Months Ended |
|||||||
| May 31, 2005 |
May 31, 2004 |
||||||
| Net income |
$ | 121,879 | $ | 369,774 | |||
| OTHER COMPREHENSIVE INCOME: |
|||||||
| Reclassification adjustment for gains (losses) on derivative instruments included in net income accounted for as hedges |
2,748 | (1,109 | ) | ||||
| Change in value of derivative instruments accounted for as hedges |
3,142 | 1,758 | |||||
| Change in value of available-for-sale securities |
60 | 49 | |||||
| Comprehensive income |
$ | 127,829 | $ | 370,472 | |||
| Reconciliation of Accumulated Other Comprehensive Income |
|||||||
| Balance, beginning of period |
$ | 11 | $ | — | |||
| Current period reclassification to earnings |
2,748 | (1,109 | ) | ||||
| Current period change |
3,202 | 1,807 | |||||
| Balance, end of period |
$ | 5,961 | $ | 698 | |||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except unit data)
(unaudited)
| Limited Partner Units |
General Partner’s Capital |
Limited Partners’ Capital |
Accumulated Other Income |
Total Partners’ Capital |
||||||||||||||
| Balance at August 31, 2004 |
194,295,631 | $ | 4,053 | $ | 364,261 | $ | 11 | $ | 368,325 | |||||||||
| Distributions |
— | (530 | ) | (62,483 | ) | — | (63,013 | ) | ||||||||||
| Net Income |
— | 1,027 | 120,852 | — | 121,879 | |||||||||||||
| Net change in Accumulated Other Comprehensive Income |
— | — | — | 5,950 | 5,950 | |||||||||||||
| Redemption and retirement of Employee Incentive Units |
(4,858,300 | ) | — | (9,166 | ) | — | (9,166 | ) | ||||||||||
| Balance, May 31, 2005 |
189,437,331 | $ | 4,550 | $ | 413,464 | $ | 5,961 | $ | 423,975 | |||||||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
| Nine-months ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Net income |
$ | 121,879 | $ | 369,774 | ||||
| Reconciliation of net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
77,110 | 34,475 | ||||||
| Amortization of deferred finance costs charged to interest |
2,746 | 2,391 | ||||||
| Write off of deferred financing fees |
6,441 | — | ||||||
| Provision for loss on accounts receivable |
4,781 | 996 | ||||||
| Loss on disposal of assets |
665 | 235 | ||||||
| Gain on Energy Transfer Transactions |
— | (320,893 | ) | |||||
| Deferred compensation on restricted units and long-term incentive plan |
1,206 | — | ||||||
| Gain on sale of discontinued operations before income tax expense |
(106,437 | ) | — | |||||
| Undistributed earnings of affiliates |
161 | (359 | ) | |||||
| Deferred income taxes |
2,498 | (827 | ) | |||||
| Minority interests |
143,527 | 33,537 | ||||||
| Distributions from subsidiary to minority unitholders |
(81,464 | ) | (17,881 | ) | ||||
| Changes in assets and liabilities, net of effect of acquisitions: |
||||||||
| Accounts receivable |
(111,889 | ) | (60,042 | ) | ||||
| Accounts receivable from related companies |
(630 | ) | (665 | ) | ||||
| Inventories |
(76,089 | ) | 50,255 | |||||
| Deposits paid to vendors |
(43,419 | ) | 17,506 | |||||
| Exchanges receivable |
(1,339 | ) | (888 | ) | ||||
| Prepaid expenses and other |
2,767 | 2,355 | ||||||
| Intangibles and other assets |
(281 | ) | (2,391 | ) | ||||
| Accounts payable |
224,046 | 32,230 | ||||||
| Accounts payable to related companies |
2,065 | (270 | ) | |||||
| Exchanges payable |
(4,568 | ) | (614 | ) | ||||
| Deposits from customers |
12,782 | (1,243 | ) | |||||
| Accrued and other current liabilities |
7,607 | (2,656 | ) | |||||
| Other long-term liabilities |
9,105 | — | ||||||
| Income taxes payable |
(1,177 | ) | (177 | ) | ||||
| Price risk management liabilities, net |
24,766 | 332 | ||||||
| Net cash provided by operating activities |
216,859 | 135,180 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Cash paid for acquisitions, net of cash acquired |
(1,117,864 | ) | (122,399 | ) | ||||
| Capital expenditures |
(118,577 | ) | (88,261 | ) | ||||
| Investment in unconsolidated subsidiaries |
(51 | ) | (250 | ) | ||||
| Proceeds from sale of discontinued operations |
191,606 | — | ||||||
| Proceeds from sale of subsidiary units |
2,631 | — | ||||||
| Proceeds from the sale of assets |
3,610 | 631 | ||||||
| Net cash used in investing activities |
(1,038,645 | ) | (210,279 | ) | ||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)
(in thousands)
(unaudited)
| Nine-months ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
| Proceeds from borrowings |
2,271,393 | 364,238 | ||||||
| Principal payments on debt |
(1,783,701 | ) | (360,659 | ) | ||||
| Net proceeds from issuance of Common Units of subsidiary |
349,749 | 334,330 | ||||||
| Distributions to partners |
(63,013 | ) | (247,228 | ) | ||||
| Debt issuance costs |
(12,842 | ) | (4,236 | ) | ||||
| Redemption and retirement of Employee Interests |
(1,045 | ) | — | |||||
| Net cash provided by financing activities |
760,541 | 86,445 | ||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
(61,245 | ) | 11,346 | |||||
| CASH AND CASH EQUIVALENTS, beginning of period |
82,852 | 55,073 | ||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 21,607 | $ | 66,419 | ||||
| NONCASH FINANCING ACTIVITIES: |
||||||||
| Notes payable incurred on noncompete agreements |
$ | 1,149 | $ | — | ||||
| Issuance of Subsidiary Common Units in connection with certain acquisitions |
$ | 2,500 | $ | 734 | ||||
| Distribution of ETP Common Units to redeem limited partner interests |
$ | 8,120 | $ | — | ||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
||||||||
| Cash paid during the period for interest, net of $191 and $717 capitalized for |
$ | 47,862 | $ | 21,252 | ||||
| Cash paid during the period for income taxes |
$ | 5,586 | $ | 4,988 | ||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands)
(unaudited)
The accompanying unaudited consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries (the “Partnership” or “ETE”) presented herein for the nine months ended May 31, 2005 and 2004, include the results of operations for Energy Transfer Partners, L.P. (“ETP”), which in turn include the results of operations for La Grange Acquisition, L.P. (dba Energy Transfer Company) (“ETC OLP”) Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.L.C. for the nine month periods ended May 31, 2005 and May 31, 2004 and the results of operations for Heritage Propane Partners, L.P. (“Heritage”), Heritage Holdings, Inc. (“HHI”), Energy Transfer Partners, GP, L.P. (formerly U.S. Propane, L.P.) (“ETP GP”), and Energy Transfer Partners, L.L.C. (formerly U.S. Propane, L.L.C.) (“ETP LLC”) for the nine months ended May 31, 2005 and only for the period from January 20, 2004 to May 31, 2004. Thus, the results of operations do not represent the entire results of operations for Heritage, HHI, ETP GP, or ETP LLC for the nine months ended May 31, 2004, as they do not include the results of operations of Heritage, HHI, ETP GP, or ETP LLC for the period prior to the Energy Transfer Transactions on January 20, 2004. The Energy Transfer Transactions are described in Note 1 below. The comparability of the accompanying condensed consolidated financial statements are also affected by other material acquisitions which are described in Note 2.
1. OPERATIONS AND ORGANIZATION:
The Partnership is a Texas limited partnership, which was formed in September 2002. On August 23, 2005, the Partnership converted from a Texas limited partnership to a Delaware limited partnership. ETE’s partnership agreement contained provisions which govern the relative ownership percentages of the Partnership.
LE GP, LLC, the general partner of ETE, is a Texas limited liability company controlled by common ownership of ETC Holdings, LP (Holdings). LE GP, LLC and the general partner of Holdings are ultimately owned and controlled by, the Co-CEOs of ETP, and Natural Gas Partners, a venture capital investor.
In September 2004, the Partnership sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, the Partnership sold a 5% limited partner interest in ETE to this group. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were contributed together with the 4.6662% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interests together were deemed to be an equivalent value of the 5% limited partner interest in ETE. The equivalent value was determined to be the book value of the Common Units and the interests in ETP GP and ETP LLC that were contributed.
Under the terms of ETE’s partnership agreement, the limited partners’ potential liability is limited to their investment in the Partnership. The general partner of ETE manages and controls the business and affairs of the Partnership. The limited partners of ETE are not involved in the management and control of ETE.
The accompanying unaudited consolidated financial statements and notes thereto of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. Due to the seasonal nature of the Partnership’s subsidiaries’ operations and the effect of acquisitions, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. For information regarding the pro forma effects of certain transactions occurring during the periods presented on the historical results of operations, see Note 2.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Equity and subsidiaries as of May 31, 2005 and the results of operations for the nine-month periods ended May 31, 2005 and 2004, respectively, and cash flows for the nine-month periods ended May 31, 2005 and May 31, 2004, respectively. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Equity presented elsewhere in this document for the fiscal year ended August 31, 2004.
On January 26, 2005, ETP completed its acquisition of the Houston Pipeline System and related storage facilities (“HPL”). For additional information regarding this acquisition and other acquisitions, see Note 3.
Energy Transfer Transactions
On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (now known as Energy Transfer Equity, L.P. (“ETE”) completed the series of transactions whereby ETE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage in exchange for cash, Common Units, Class D Units and Special Units of Heritage. Simultaneously, ETE acquired the General Partner of Heritage, ETP GP, and ETP LLC from their owners, and coupled with the Heritage Limited Partner interests ETE received, thereby gained control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings (“HHI”) from the owners of ETP GP.
Subsequent to the Energy Transfer Transactions, Heritage changed its name to Energy Transfer Partners, L.P., and began trading on the New York Stock Exchange under the ticker symbol “ETP”. The name change and new ticker symbol were effective March 1, 2004.
Accounting Treatment of the Energy Transfer Transactions
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards 141, Business Combinations (“SFAS 141”). Although Heritage was the surviving parent entity for legal purposes, ETE was the acquirer for accounting purposes. Consequently, the Company’s financial statements do not reflect 100% of the results of Heritage, HHI, ETP GP, or ETP LLC within the period, as those results prior to January 19, 2004 (the date of the Energy Transfer Transactions) are not included. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The Partnership, in accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141 recorded a gain of approximately $395,000 as a result of the Energy Transfer Transactions. ETE accounted for the transaction as a partial sale of ETC OLP and a partial acquisition of Heritage, and recognized the gain to the extent ETC OLP was sold and stepped up the assets of ETC OLP to the extent ETC OLP was acquired by the minority shareholders. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by ETE through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%.
The acquisition of HHI by Heritage was accounted for as a capital transaction at ETP as the primary asset held by HHI was 8,853,832 Common Units of ETP on a post-split basis (see “Other Developments” below). Following the acquisition of HHI by ETP, the Heritage Common Units held by HHI were converted to Class E Units of ETP.
F-83
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The issuance of the additional ETP Common Units upon the conversion of ETP Special Units adjusted the percent of Heritage acquired by ETE in the Energy Transfer Transactions and resulted in an additional fair value step-up being recorded on Heritage’s assets in accordance with EITF 90-13. Upon the conversion of the Special Units on June 23, 2004, ETE acquired approximately 41.5% of Heritage.
The excess purchase price over Heritage’s cost was determined as follows:
| Net book value of Heritage at January 20, 2004 |
$ | 239,102 | ||
| Historical goodwill at January 20, 2004 |
(170,500 | ) | ||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 267,210 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Equity interest acquired |
$ | 110,892 | ||
| Fair market value of Limited Partner Units |
668,534 | |||
| Purchase price of General Partner Interest |
30,000 | |||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 897,142 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Fair value of equity acquired |
372,314 | |||
| Net book value of equity acquired |
110,892 | |||
| Excess purchase price over Heritage cost |
$ | 261,422 | ||
The excess purchase price over Heritage cost was allocated as follows:
| Property, plant and equipment (25 year life) |
$ | 35,269 | |
| Customer lists (15 year life) |
18,926 | ||
| Trademarks |
19,251 | ||
| Goodwill |
187,976 | ||
| $ | 261,422 | ||
Goodwill was warranted in the Energy Transfer Transactions because the business enterprise value of the operations acquired exceeded the fair market value of the tangible and identifiable intangible assets acquired. The allocation of the purchase price reflects the final assessment of asset values of Heritage acquired in the Energy Transfer Transactions.
F-84
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The gain recognized by ETE as a result of the Energy Transfer Transactions was determined as follows:
| ETE’s historical basis in ETC OLP |
$ | (90,906 | ) | |
| Percent sold in Energy Transfer Transactions |
58.5 | % | ||
| (53,180 | ) | |||
| Fair value of equity acquired in Energy Transfer Transactions |
372,314 | |||
| Less: Consideration paid for ETP’s GP interest |
$ | (30,000 | ) | |
| Fair value of assets received in EnergyTransfer Transactions |
$ | 342,314 | ||
| Gain on partial sale of ETC OLP |
$ | 395,494 | ||
The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE in the Energy Transfer Transactions of approximately 58.5%, determined in accordance with Emerging Issues Task Force EITF 90-13 and SFAS 141. The step up resulted in an approximate $504,000 increase to property, plant and equipment at ETE which is being depreciated over estimated lives 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributable to a taxable subsidiary of ETC OLP, resulting in approximately $108.5 million of deferred taxes recorded by ETE. The deferred tax liabilities will reverse at the same rate as the related step-up in assets will be depreciated.
As of May 31, 2004, the Partnership had recorded a gain of $320,893, which did not include the effect of the conversion of ETP Special Units. The conversion of the Special units to Common Units of ETP adjusted the percent of ETC OLP retained by the Partnership in the Energy Transfer Transactions and resulted in an additional step-up and gain being recorded on ETC OLP’s assets in accordance with EITF 90-13.
Accounting Treatment of the General Partner Transaction
Goodwill of $29,589 was recorded in connection with ETE’s acquisition of ETP GP. Goodwill was warranted because, as the General Partner of ETP, ETP GP owns certain incentive distribution rights, which entitle it to receive distributions in excess of its 2% general partner interest in ETP.
Business Operations
Subsequent to the Energy Transfer Transactions described above, ETE conducts business operations only through the two wholly owned operating partnerships of ETP: ETC OLP and HOLP (collectively the “Operating Partnerships”).
ETC OLP is engaged in midstream natural gas and transportation operations. ETC OLP owns and operates natural gas gathering, natural gas intrastate pipeline systems, and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and Louisiana. ETC OLP is a Texas limited partnership formed in October 2002 and was 99.9% owned by the Partnership prior to the Energy Transfer Transactions and is 99.9% owned by ETP subsequent to the Energy Transfer Transactions and 0.1% owned by ETC OLP’s general partner LA GP, LLC, a wholly-owned subsidiary of ETP. ETC OLP is the 99.9% limited partner to ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Oklahoma Pipeline Ltd (the “Elk City System”), which was sold on
F-85
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
April 14, 2005, ETC Katy Pipeline, Ltd., ETC Processing, Ltd. and ETC Marketing, Ltd. and the 99% limited partner to ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. (collectively, the “Operating Companies”) ETC Oklahoma Pipeline Ltd is presented as discontinued operations in the Partnership’s consolidated financial statements. ETC OLP also owns a 50% interest in Vantex Gas Pipeline Company, LLC, a 50.5% interest in Vantex Energy Services, Ltd., and a 49% interest in Ranger Pipeline, L.P. These investments are accounted for under the equity method of accounting as ETC OLP exercises significant influence over these entities but lacks controlling interests. On June 29, 2005, ETP bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd. ETC OLP was contributed to Heritage on January 19, 2004, to become a wholly-owned subsidiary of ETP.
As of May 31, 2005, ETC OLP owns an interest in and operates approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to its gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities. The midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. The transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, the East Texas Pipeline, the natural gas pipeline and storage assets that are referred to as the ET Fuel System, and the natural gas pipeline and storage assets of the recently acquired HPL System.
The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Pipeline. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas.
The transportation and storage segment also includes the recently acquired HPL System which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. The HPL System consists of six main transportation pipelines and three market area loops and has direct access to multiple market hubs at Katy, the Houston Ship Channel, Ague Dulce and through its operations of the Bammel storage facility.
ETP also recently announced the completion of the Fort Worth Basin Pipeline. The 55-mile, 24 inch natural gas pipeline connects to our existing pipelines in North Texas and provides transportation for natural gas production from the Barnett Shale producing area. The construction costs were financed entirely with cash from operations. Results of operations for the nine months ended May 31, 2005 from the Fort Worth Basin Pipeline were not significant.
F-86
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
HOLP, a Delaware limited partnership, is engaged in retail and wholesale propane operations. HOLP sells propane and propane-related products to more than 700,000 active residential, commercial, industrial, and agricultural customers in 34 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership, a Canadian partnership in which the Partnership owns a 60% interest, is engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP enters into forward purchases and sales agreements for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C.
Other Developments
On January 27, 2005, ETP announced that the Board of Directors of its general partner approved a two-for-one split for each class of ETP’s limited partner units. The split entitled ETP’s Unitholders of record at the close of business on February 28, 2005 to receive one additional ETP Partnership unit for each ETP Partnership unit owned on that date. The distribution was made on March 15, 2005. The effect of the split was to double the number of all outstanding ETP Common Units and to reduce by half ETP’s minimum quarterly per unit distribution and the targeted distribution levels. All periods presented and all references to Common Units of ETP have been restated to reflect the effects of the unit split.
On June 20, 2005, ETP completed the sale of 1,640,000 Common Units to a group of executive managers of ETP. The proceeds were approximately $52,000, of which $30,000 was used to pay outstanding debt of ETP and the remaining proceeds will be used for ETP’s general partnership purposes. ETP sold a 5% limited partner interest to this group in exchange for its contribution of 1,638,692 Common Units of ETP, its 4.9995% limited partner interest in ETP GP and 5% of the member interests of ETP LLC pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. The value of the contribution and the interests received in exchange for those contributions were equivalent and were recorded at the value of the Common Units and limited partner interests and member interests received. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were contributed together with the 4.6662% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interests together were deemed to be an equivalent value of the 5% limited partner interest in ETE.
New Accounting Standards
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require the Partnership to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Partnership’s financial statements.
SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The Partnership does not expect SFAS 123R to have a material impact on its consolidated results of operations, cash flows or financial position.
F-87
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.
EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The Partnership accounted for the sale of its discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.
EITF Issue No. 03-6 (“EITF 03-6). “Participating Securities and the Two-Class method under FASB Statement No. 128.” EITF 03-6 requires the calculation of net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings, as if all of the earnings for the period had been distributed. In periods with undistributed earnings above certain levels, the calculation according to the two-class method results in an increased allocation of undistributed earnings to the general partner of ETP and a dilution of the earnings to the limited partners. In periods that may have year-to-date net losses the allocation of the net losses to the limited partners and the general partner of ETP will be determined based on the same allocation basis specified in the ETP Partnership Agreement that would apply to periods in which there were no undistributed earnings. ETP follows the requirements of EITF 03-6 in calculating their net earnings per limited partner unit and EITF 03-6 is not applicable to ETE.
F-88
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
2. PRESENTATION OF FINANCIAL INFORMATION:
Principles of Consolidation
The accompanying consolidated statement of operations for the nine months ended May 31, 2004 include the results of operations for ETE consolidated with the results of operations of ETC OLP and the Operating Companies, beginning September 1, 2003, and the results of operations of ETP, HOLP, HHI, ETP GP, and ETP LLC beginning January 20, 2004.
The accompanying consolidated financial statements for the nine months ended May 31, 2005 include the results of operations for ETE consolidated with the results of operations of ETC OLP, HOLP, HHI, ETP, ETP GP and ETP LLC. In addition, ETP acquired the controlling interests in HPL on January 26, 2005. The results of operations for the ET Fuel System and HPL are included in the consolidated statement of operations since their respective acquisition dates. The accompanying financial statements for the nine month period ended May 31, 2004 include the results of operations for ETC OLP beginning September 1, 2003, consolidated with the results of operations of HOLP, HHI, ETP, ETP GP and ETP LLC beginning January 20, 2004 after the elimination of significant intercompany balances and transactions. Additionally, on June 2, 2004, ETC OLP acquired the ET Fuel System from TXU Fuel Company, a subsidiary of TXU Corp.
The following pro forma consolidated results of operations for the nine months ended May 31, 2005 are presented as if the HPL acquisition had been made on September 1, 2004. The pro forma consolidated results of operations for the nine months ended May 31, 2004 are presented as if the ET Fuel System acquisition, the HPL acquisition, and the Energy Transfer Transactions had been made on September 1, 2003. The pro forma consolidated results of operations include the income from discontinued operations as presented on the consolidated income statements for the periods presented below.
| Nine Months Ended 2005 |
Nine Months Ended 2004 | |||||
| Revenues |
$ | 6,004,015 | $ | 4,728,177 | ||
| Net income |
$ | 130,157 | $ | 62,174 | ||
| Basic earnings per Limited Partner Unit |
$ | 0.66 | $ | 0.35 | ||
| Diluted earnings per Limited Partner Unit |
$ | 0.53 | $ | 0.25 | ||
The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt and certain other adjustments. The pro forma consolidated results include income from discontinued operations and the gain on the sale of discontinued operations and exclude the gain on the Energy Transfer Transactions. The pro forma consolidated results of operations do not include the effects of the Texas Chalk and Madison Systems acquired in November 2004 or the acquisition of seven propane businesses that were acquired during the nine months ended May 31, 2005 or propane acquisitions that were completed during the nine months ended May 31, 2004. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
F-89
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
3. ACQUISITIONS:
In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Gas Services for $64,632 in cash, which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $66,667 which included $64,632 of cash paid and liabilities assumed of $2,035. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets were integrated into ETP’s Southeast Texas System and are expected to provide increased throughput capacity to ETP’s existing midstream assets. The acquisition was not material for pro forma disclosure purposes.
In January 2005, ETP acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350,000 of ETP Common Units. In addition, ETP acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing which was re-paid in full prior to May 31, 2005. The total purchase price of $1,410,189 which included $1,039,358 of cash paid, net of cash acquired and liabilities assumed of $413,270, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Included in prepaid expenses and other on the consolidated balance sheet as of May 31, 2005 is $42,400 in receivables due from AEP related to the HPL acquisition. Under the terms of the transaction, ETP, through ETC OLP, its wholley-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables ETP to expand its current transportation systems into areas where it previously did not have a presence, and in combination with ETP’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in ETP’s transportation and storage operating segment.
During the nine months ended May 31, 2005, HOLP acquired substantially all of the assets of seven propane businesses. The aggregate purchase price for these acquisitions totaled $18,109 which included $13,875 of cash paid, net of cash acquired, 120,550 Common Units on a post-split basis valued at $2,500 when issued and liabilities assumed of $1,734. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for these acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.
Each of these acquisitions was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, and each purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition. The results of operations for these acquisitions are included in the Consolidated Statement of Operations from the date of the respective acquisition.
F-90
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on the fair values for these acquisitions (in thousands):
| Texas Chalk and Madison Systems November 2004 |
HPL January 2005 |
HOLP acquisitions (aggregated) |
||||||||||
| Cash and equivalents |
$ | — | $ | 191 | $ | 5 | ||||||
| Accounts receivable |
— | 370,378 | 429 | |||||||||
| Inventory |
— | 130,280 | 243 | |||||||||
| Other current assets |
— | 23,567 | 184 | |||||||||
| Investments in unconsolidated affiliate |
— | 32,940 | — | |||||||||
| Price risk management assets |
— | 28,638 | — | |||||||||
| Property, plant, and equipment |
66,667 | 824,386 | 11,074 | |||||||||
| Intangibles |
— | — | 3,740 | |||||||||
| Goodwill |
— | — | 2,439 | |||||||||
| Total assets acquired |
66,667 | 1,410,380 | 18,114 | |||||||||
| Accounts payable |
(525 | ) | (313,469 | ) | (233 | ) | ||||||
| Accrued expenses |
(1,510 | ) | (36,077 | ) | (352 | ) | ||||||
| Other current liabilities |
— | (13,247 | ) | — | ||||||||
| Other liabilities |
— | (6,710 | ) | — | ||||||||
| Price risk management liabilities |
— | (28,638 | ) | — | ||||||||
| Long-term debt |
— | — | (1,149 | ) | ||||||||
| Minority interest |
— | (15,129 | ) | — | ||||||||
| Total liabilities assumed |
(2,035 | ) | (413,270 | ) | (1,734 | ) | ||||||
| Net assets acquired |
$ | 64,632 | $ | 997,110 | $ | 16,380 | ||||||
The purchase prices have been allocated by ETP based on the fair values of the assets acquired and liabilities assumed at the date of acquisition. The preliminary allocation may be adjusted to reflect the final purchase price allocation which will be based on an independent appraisal, if applicable. In addition, ETP continues to evaluate the acquisition of HPL and further adjustments may be necessary following an independent appraisal of fair market values, completion of the working capital settlement, and other adjustments under the purchase and sale agreement.
During the nine months ended May 31, 2005, ETP completed a verification of the working gas inventory contained in the storage facilities it had acquired in two acquisitions and has adjusted the preliminary allocations of the purchase prices to reflect the verified amounts. AEP has notified ETP that it intends to review the results of the verification pertaining to the HPL acquisition, and further adjustments may be necessary based on the final outcome of AEP’s review and any final determinations made in accordance with the purchase and sale agreement.
4. DISCONTINUED OPERATIONS:
On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191,606, including certain adjustments as defined in the purchase and sale agreement. The sale of the Elk City System has been accounted for as discontinued
F-91
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
operations. These results are presented as net amounts in the Consolidated Statements of Operations, with prior periods restated to conform to the current presentation. Selected operating results for these discontinued operations are presented in the following table:
| Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| Revenues |
$ | 105,542 | $ | 94,792 | ||||
| Cost and expenses |
(100,044 | ) | (90,663 | ) | ||||
| Net income |
$ | 5,498 | $ | 4,129 | ||||
5. USE OF ESTIMATES:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, deferred taxes, and fair values of unit based compensation Actual results could differ from those estimates.
6. ACCOUNTS RECEIVABLE:
Accounts receivable consisted of the following, excluding amounts from discontinued operations:
| May 31, 2005 |
August 31, 2004 |
|||||||
| Accounts receivable midstream and transportation |
$ | 665,966 | $ | 206,023 | ||||
| Accounts receivable propane |
67,277 | 46,990 | ||||||
| Less—allowance for doubtful accounts |
(3,982 | ) | (1,667 | ) | ||||
| Total, net |
$ | 729,261 | $ | 251,346 | ||||
The activity in the allowance for doubtful accounts for the retail and wholesale propane segments for periods presented, consisted of the following:
| Nine Months Ended | |||||||
| May 31, 2005 |
May 31, 2004 | ||||||
| Balance, beginning of period |
$ | 1,667 | $ | — | |||
| Provision for loss on accounts receivable |
4,781 | 996 | |||||
| Accounts receivable written off, net of recoveries |
(2,466 | ) | — | ||||
| Balance, end of period |
$ | 3,982 | $ | 996 | |||
F-92
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
7. INVENTORIES:
Inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following, excluding amounts related to discontinued operations:
| May 31, 2005 |
August 31, 2004 | |||||
| Natural gas, propane and other NGLs |
$ | 247,665 | $ | 40,926 | ||
| Appliances, parts and fittings and other |
13,748 | 12,335 | ||||
| Total inventories |
$ | 261,413 | $ | 53,261 | ||
8. PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Partnership capitalizes certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.
The Partnership reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the periods presented.
F-93
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
Components and useful lives of property, plant and equipment were as follows, excluding assets held for sale:
| May 31, 2005 |
August 31, 2004 |
|||||||
| Land and improvements |
$ | 37,882 | $ | 28,156 | ||||
| Buildings and improvements (10 to 30 years) |
57,797 | 37,201 | ||||||
| Pipelines and equipment (10 to 65 years) |
1,988,278 | 1,279,755 | ||||||
| Natural gas storage (40 years) |
29,862 | 24,277 | ||||||
| Bulk storage, equipment and facilities (3 to 30 years) |
56,321 | 52,007 | ||||||
| Tanks and other equipment (5 to 30 years) |
353,591 | 321,511 | ||||||
| Vehicles (5 to 10 years) |
76,766 | 56,740 | ||||||
| Right of way (20 to 65 years) |
95,150 | 65,924 | ||||||
| Furniture and fixtures (3 to 10 years) |
10,249 | 7,324 | ||||||
| Linepack |
23,896 | 12,802 | ||||||
| Pad gas |
102,557 | 42,136 | ||||||
| Other (5 to 10 years) |
21,147 | 5,581 | ||||||
| 2,853,496 | 1,933,414 | |||||||
| Less—Accumulated depreciation |
(130,896 | ) | (61,051 | ) | ||||
| 2,722,600 | 1,872,363 | |||||||
| Plus—Construction work-in-process |
101,772 | 42,911 | ||||||
| Property, plant and equipment, net |
$ | 2,824,372 | $ | 1,915,274 | ||||
Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate. For the nine months ended May 31, 2005 and 2004 a total of $191 and $717, respectively was capitalized for pipeline construction projects.
F-94
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
9. GOODWILL:
Goodwill is associated with acquisitions made for ETE’s segments as presented in the table below. Of the $351,320 balance in goodwill, $26,027 is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill for the nine months ended May 31, 2005 were as follows:
| Midstream |
Transportation and Storage |
Retail Propane |
Other |
Total | |||||||||||
| Balance as of August 31, 2004 |
$ | 13,409 | $ | 10,327 | $ | 295,469 | $ | 29,556 | $ | 348,761 | |||||
| Goodwill acquired during the period |
— | — | 2,527 | 32 | 2,559 | ||||||||||
| Impairment losses |
— | — | — | — | — | ||||||||||
| Balance as of May 31, 2005 |
$ | 13,409 | $ | 10,327 | $ | 297,996 | $ | 29,588 | $ | 351,320 | |||||
| Midstream |
Transportation and Storage |
Retail Propane |
Other |
Total | |||||||||||
| Balance as of August 31, 2003 |
$ | 13,409 | $ | — | $ | — | $ | — | $ | 13,409 | |||||
| Goodwill acquired during the year |
— | 10,327 | 272,373 | 30,666 | 313,366 | ||||||||||
| Impairment losses |
— | — | — | — | — | ||||||||||
| Balance as of May 31, 2004 |
$ | 13,409 | $ | 10,327 | $ | 272,373 | $ | 30,666 | $ | 326,775 | |||||
10. DEPOSITS:
Deposits are paid to vendors in ETP’s midstream and transportation and storage business as prepayments for natural gas deliveries in the following month. ETC OLP makes prepayments when the volume of business with a vendor exceeds ETC OLP’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $3,747 and $3,000 as of May 31, 2005 and August 31, 2004, respectively. ETP uses a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage its exposure to market fluctuations in the prices of natural gas and NGLs. ETP enters into these financial instruments with brokers who are clearing members with the NYMEX and directly with counterparties in the over-the-counter (“OTC”) market and is subject to margin deposit requirements under the OTC agreements and NYMEX positions. The NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by the counterparties when the financial instrument settles. ETP also has maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative(s) exceed(s) ETP’s pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date. ETP also has deposits with derivative counterparties of $42,694 and $23 as of May 31, 2005 and August 31, 2004, respectively.
Deposits are received from ETP’s midstream and transportation and storage customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane use. Prepayments and security deposits may also be required when ETP’s customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $24,978 and $11,378 as of May 31, 2005 and August 31, 2004, respectively.
F-95
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
11. INCOME PER LIMITED PARTNER UNIT:
Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner units outstanding. Diluted net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner units outstanding and the weighted average number of ETE Incentive Units granted. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
| For the Nine Months Ended | ||||||
| May 31, 2005 |
May 31, 2004 | |||||
| Basic Net Income per Limited Partner Unit: |
||||||
| Limited Partners’ interest in net income |
$ | 120,852 | $ | 366,483 | ||
| Weighted average limited partner units |
194,171,059 | 174,081,485 | ||||
| Limited Partners’ income from continuing operations |
$ | 0.33 | $ | 2.10 | ||
| Limited Partners’ income from discontinued operations |
0.29 | 0.01 | ||||
| Basic net income per limited partner unit |
$ | 0.62 | $ | 2.11 | ||
| Diluted Net Income per Limited Partner Unit: |
||||||
| Limited partners’ interest in net income |
$ | 120,852 | $ | 366,483 | ||
| Weighted average limited partner units |
194,171,059 | 174,081,485 | ||||
| Dilutive effect of Employee Incentive units |
48,582,996 | 68,246,698 | ||||
| Weighted average limited partner units, assuming dilutive effect of Employee Incentive units |
242,754,055 | 242,328,183 | ||||
| Limited Partners’ income from continuing operations |
$ | 0.27 | $ | 1.50 | ||
| Limited Partners’ income from discontinued operations |
0.23 | 0.01 | ||||
| Diluted net income per limited partner unit |
$ | 0.50 | $ | 1.51 | ||
12. EMPLOYEE INCENTIVE INTERESTS:
ETE’s partnership agreement as amended and restated provides for certain incentive interests for certain employees. The employee incentive interests consists of 12,145,749 Employee Incentive Units granted to certain employees on the formation of ETE (the “Employee Incentive Units”).
The Employee Incentive Units vest ratably over a three-year period from the date of grant or fully vest upon the occurrence of a Fundamental Change as defined in ETE’s partnership agreement. The Employee Incentive Units were limited partner interests in ETE (as defined in the amended and restated agreement of limited partnership of ETE) and afforded the recipients with certain rights as limited partners in accordance with their terms. Employees must forfeit all vested and unvested Employee Incentive Units when the employee voluntarily terminates his or her employment or is terminated with cause as defined in ETE’s partnership agreement. The Employee Incentive Units granted shall be forfeited upon the fifth anniversary of the grant if the required “Tier I Payout,” as defined in ETE’s partnership agreement, has not yet occurred.
F-96
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The Partnership accounts for the Employee Incentive Interests in accordance with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123). Under SFAS 123, total compensation is measured at the fair value of the award on the grant date and compensation expense is recorded ratably over the service period. Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive until vesting of the Employee Incentive Interests. Accordingly, no expense was recorded in the Partnership’s consolidated financial statements for the nine months ended May 31, 2005 or 2004 and no expense related to the Employee Incentive Units issued upon formation of ETE will be recorded in any subsequent period.
As a result of The Energy Transfer Transactions in January 2004, all Employee Incentive Units vested and were converted to limited partner interests, and the “Tier I Payout” was met giving effective rights as a limited partner in ETE to the holders of the Employee Incentive Units who ceased to be employees of ETE and became employees of ETP and its subsidiaries. In May 2005, ETE exchanged 631,320 ETP Common Units held by ETE and $1,046 in cash for the redemption of 4,858,300 limited partner interests in ETE, which were then retired. The redemption was determined to be no more than the fair value of the respective interests in ETE.
13. OTHER INCENTIVE INTERESTS:
ETE’s partnership agreement provides for 72,874,494 Incentive Units (the ETE Incentive Units), consisting of: 24,291,498 “Tier I Units;” 12,145,749 “Tier II Units;” 12,145,749 “Tier III Units;” and 24,291,498 “Tier IV Units” to be granted to ETC Holdings, LP, one of ETE’s limited partners, if certain “Tier” payouts are achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 24,291,498 ETE Incentive Units held by ETC Holdings vested and were converted to limited partner interests in the Partnership and the “Tier 1” payout was met giving ETC Holdings effective rights in additional limited partner interests in the Partnership. Subsequent to May 31, 2005, the remaining “Tier” payout conditions as defined in the Partnership Agreement were achieved and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership.
14. UNIT BASED COMPENSATION PLANS:
The Partnership follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-based Compensation (SFAS 123) for ETE’s Employee Incentive Interests and ETP’s unit based compensation plans. SFAS 123 requires that significant assumptions be used during the period to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. ETP assumed a weighted average risk-free interest rate of 2.83% for the nine months ended May 31, 2005, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. The average fair value of the awards granted during the nine months ended May 31, 2005 was $34.00. Annual average cash distributions at the grant date were estimated to be $1.63 on a post-split basis for the nine months ended May 31, 2005. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. ETP recognized compensation expense of $1,206 during the nine months ended May 31, 2005 related to unit based compensation plans. ETP did not recognize any compensation expense for the nine months ended May 31, 2004 as no awards related to these plans were issued during the nine months ended May 31, 2004.
Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive prior to vesting of the
F-97
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
Employee Incentive Interests. Accordingly, no expense was recorded in the Partnership’s consolidated financial statements for the nine months ended May 31, 2004, nor would any expense related to the Employee Incentive Units issued upon formation of ETE be recorded in any subsequent period. As a result of the Energy Transfer Transaction in January 2004, all Employee Incentive Units vested and were converted to limited partner interests and the “Tier I Payout” was met giving effective rights as a limited partner in ETE to the holders of the Employee Incentive Units who ceased to be employees of ETE and became employees of ETP and its subsidiaries.
15. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:
Long-term debt of ETP and its operating subsidiaries consists of the following on a consolidated basis:
| May 31, 2005 |
August 31, 2004 |
|||||||
| HOLP Notes |
||||||||
| 1996 8.55% Senior Secured Notes |
$ | 84,000 | $ | 84,000 | ||||
| 1997 Medium Term Note Program: |
||||||||
| 7.17% Series A Senior Secured Notes |
12,000 | 12,000 | ||||||
| 7.26% Series B Senior Secured Notes |
16,000 | 18,000 | ||||||
| 6.50% Series C Senior Secured Notes |
714 | 1,786 | ||||||
| 2000 and 2001 Senior Secured Promissory Notes: |
||||||||
| 8.47% Series A Senior Secured Notes |
9,600 | 9,600 | ||||||
| 8.55% Series B Senior Secured Notes |
27,429 | 27,429 | ||||||
| 8.59% Series C Senior Secured Notes |
27,000 | 27,000 | ||||||
| 8.67% Series D Senior Secured Notes |
58,000 | 58,000 | ||||||
| 8.75% Series E Senior Secured Notes |
7,000 | 7,000 | ||||||
| 8.87% Series F Senior Secured Notes |
40,000 | 40,000 | ||||||
| 7.21% Series G Senior Secured Notes |
11,400 | 15,200 | ||||||
| 7.89% Series H Senior Secured Notes |
8,000 | 8,000 | ||||||
| 7.99% Series I Senior Secured Notes |
16,000 | 16,000 | ||||||
| 2005 5.95% Senior Notes, net of discount of $2,203 |
747,797 | — | ||||||
| ETC OLP Term Loan Facility |
— | 725,000 | ||||||
| HOLP Senior Revolving Acquisition Facility |
41,000 | 23,000 | ||||||
| ETP Revolving Credit Facility |
443,000 | — | ||||||
| ETP Swingline Loans |
30,000 | — | ||||||
| HOLP Long term portion of the Senior Revolving Working Capital Facility |
6,493 | 10,000 | ||||||
| HOLP Notes Payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010 |
16,370 | 18,218 | ||||||
| Other |
1,777 | 2,160 | ||||||
| Current maturities of long-term debt |
(33,425 | ) | (31,235 | ) | ||||
| $ | 1,570,155 | $ | 1,071,158 | |||||
F-98
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure HOLP’s Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, HOLP is required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status. As of May 31, 2005 the HOLP Notes were rated investment grade thereby alleviating the requirement that HOLP pay the additional 1% interest.
On January 18, 2005, in a Rule 144A and Regulation S under the Securities Act of 1933 private placement offering, ETP issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. ETP recorded debt issue costs of $6,413 and a discount of $2,265 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. As a result of the repayment, ETP wrote off $7,996 in deferred financing costs and accounted for the write-off as loss on extinguishment of debt in the consolidated statements of operations for the nine months ended May 31, 2005.
ETC OLP and its designated subsidiaries act as the guarantor of the debt obligations for the ETP Senior Unsecured Notes issued on January 18, 2005 and ETP Revolving Credit Facility. If ETP were to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. ETP’s Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured debt.
Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $75,000 HOLP Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.000% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the HOLP facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Working Capital Facility. Letter of Credit exposure plus the HOLP Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility. As of May 31, 2005, HOLP’s Senior Revolving Working Capital Facility had a balance outstanding of $6,493, which was long-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of its Working Capital Facility. HOLP completed the 30-day clean down requirement under its Senior Revolving Working Capital Facility on June 14, 2005 and had outstanding Letters of Credit of $1,002 at May 31, 2005.
A $75,000 Senior Revolving Acquisition Facility is available to HOLP through December 31, 2006. Amounts borrowed under the HOLP Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.715% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure its Senior Revolving Acquisition Facility. As of May 31, 2005, the HOLP Senior Revolving Acquisition Facility had a balance outstanding of $41,000.
F-99
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The agreements for each of HOLP’s Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and HOLP’s bank credit facilities contain customary restrictive covenants applicable to the Operating Partnerships, including limitations on substantial disposition of assets, changes in ownership of the Operating Partnerships, the level of additional indebtedness and creation of liens. These covenants require HOLP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than, 4.50 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon HOLP EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that HOLP may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) HOLP’s restricted payment is not greater than the product of it’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
In addition, the Indenture relating to ETP’s Senior Notes issued on January 18, 2005 and its Revolving Credit Facility contain various covenants related to ETP’s ability to incur certain indebtedness, grant certain liens, enter into certain merger, sale or consolidation transactions, enter into sale-lease back transactions, and make certain investments. ETP’s Revolving Credit Facility also requires ETP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as similarly defined in ETP’s Revolving Credit Agreement) of not more than 4.50 to 1.00 at any time other than during a Specified Acquisition Period (as similarly defined in ETP’s Revolving Credit Agreement) and 5.00 to 1.00 during a Specified Acquisition Period. The ratio of Consolidated EBITDA for each period of four consecutive fiscal quarters, to Consolidated Interest Expense (as similarly defined in ETP’s Revolving Credit Agreement), will never be less than 3.00 to 1.00.
Failure to comply with the various restrictive and affirmative covenants of the discussed credit facilities and agreements could negatively impact the Partnership’s ability to incur additional debt and/or the Partnership’s ability to pay distributions. ETP and HOLP are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to ETP’s and HOLP’s debt agreements as of May 31, 2005.
On January 26, 2005, the Partnership borrowed $200,000 under a Senior Secured Term Facility with Goldman Sachs Credit Partners L.P., secured by the Partnership’s investment in ETP. The interest rate was based on either a Eurodollar rate plus 1.25% per annum, or a prime rate plus 0.250% per annum. Of the proceeds, $174,624 was used to finance the acquisition of working inventory of natural gas from HPL (see Note 3). The remaining proceeds of approximately $25,000 were re-paid in February 2005. The loan was paid in full April 14, 2005.
F-100
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
On June 16, 2005, the Partnership entered into a $600,000 Senior Secured Loan Agreement with Goldman Sachs Credit Partners L.P., as administrative agent, and a syndicate of financial institutions that matures on June 16, 2008. Loans in an amount of $600,000 were borrowed and loans repaid under the term loan agreement may not be re-borrowed. The loans are secured by the Partnership’s ETP Common Units and general partner interest in ETP. The Partnership’s Senior Secured Loan Agreement requires that, on the last day of the specified fiscal quarter, the ratio of its Consolidated Funded Debt (as defined in the term loan agreement) to the Partnership’s Consolidated EBITDA (as defined in the term loan agreement) for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. The Partnership’s term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Partnership’s term loan agreement) to its Consolidated Interest Expense (as defined in the Partnership’s term loan agreement) must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008.
Also on January 18, 2005, ETP entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under ETP’s Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. ETP borrowed $475,000 under its Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of May 31, 2005, $443,000 was outstanding under its Revolving Credit Facility. There was also $850 in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing. ETP’s Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 at a daily rate based on the London market. As of May 31, 2005, $30,000 was outstanding under the Swingline loan option. Total amount available under ETP’s Credit Agreement as of May 31, 2005 was $256,150. Effective June 2, 2005, ETP increased its unsecured Revolving Credit Facility from $700,000 to $800,000.
Future maturities of long-term debt for the remainder of the current fiscal year, each of the next five fiscal years and thereafter are $21,021 remaining in 2005; $39,478 in 2006; $86,657 in 2007; $45,923 in 2008; $43,059 in 2009; $513,564 in 2010; and $847,344 thereafter.
Based on the estimated borrowing rates currently available to the Partnership for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at May 31, 2005 was $1,619,071 and $1,597,046, respectively. At August 31, 2004, the aggregate fair value and carrying amount was $1,128,536 and $1,102,393, respectively.
Debt transactions subsequent to May 31, 2005
On July 29, 2005 ETP completed an offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, whereby ETP issued $400,000 in aggregate principal amount of 5.65% Senior unsecured notes due 2012. The net proceeds of approximately $397,000 were used to repay a portion of the outstanding indebtedness on ETP’s Revolving Credit Facility. ETP’s Senior Notes due 2012 are fully and unconditionally guaranteed by ETC OLP and its subsidiaries guaranteeing ETP’s 5.95% Senior Notes due 2015.
On July 29, 2005, ETP also completed a registered exchange offer to exchange newly issued 5.95% Senior Notes due 2015 which have been registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old
F-101
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
Notes). The sole purpose of the exchange offer is to fulfill the obligations of ETP under the registration rights agreement entered into in connection with the sale by ETP of the Old Notes. The New Notes issued pursuant to the exchange offer will have substantially identical terms to the Old Notes.
16. INVESTMENT IN UNCONSOLIDATED AFFILIATES:
ETP owns interests in a number of related businesses that are accounted for using the equity method. In general, ETP uses the equity method of accounting for an investment in which there is a 20% to 50% ownership of its outstanding ownership interests and exercises significant influence over its operating and financial policies.
As a result of the HPL acquisition (see Note 3), ETP acquired a 50% ownership interest in Mid Texas Pipeline Company (MidTexas) which owns a 129-mile transportation pipeline system that connects various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. The investment is accounted for using the equity method of accounting. ETP does not exercise management control over MidTexas, and therefore, ETP is precluded from consolidating the MidTexas financial statements with those of its own.
The equity in earnings of unconsolidated affiliates, individually or in the aggregate, was not significant for the periods presented.
17. COMMITMENTS AND CONTINGENCIES:
Commitments
ETP has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 415 MMBtu/d. Long-term contracts require delivery of up to 515 MMBtu/d. The long-term contracts run through October 2012.
In connection with the acquisition of the ET Fuel System in June of 2004, ETP entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. ETP also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005, ETP was entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, ETP recognized an additional $14,716 in fees during the nine months ended May 31, 2005. TXU Shipper has notified ETP that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.
ETP has signed long-term agreements with several parties committing firm transportation volumes into the East Texas Pipeline which is part of the East Texas Pipeline System. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational, and expires in June 2012.
In connection with the HPL acquisition in January 2005, ETP acquired a sales agreement whereby ETP is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 1.8 million MMBtu,
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. ETP also assumed a contract with a service provider which obligates ETP to obtain certain compressor, measurement and other services through 2007 with monthly payments of approximately $1,700.
ETP in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. ETP believes that such terms are commercially reasonable and will not have a material adverse effect on ETP’s financial position or results of operations.
ETP has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices. The contracts expire at various dates through March 2006.
Litigation
ETP’s midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.
Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or are named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. ETP maintains liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.
Of the pending or threatened matters in which ETP or its subsidiaries is a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the SCANA litigation). Prior to trial, a settlement was reached with defendant, Cornerstone Ventures, L.P., and they were dismissed from the litigation. The trial began on October 4, 2004 against the remaining defendants and testimony was concluded on October 20, 2004. On October 21, 2004, the jury returned a verdict in favor of HOLP against SCANA and in favor of defendant Suburban. The jury found in favor of HOLP on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. SCANA has appealed the jury’s decision, and currently the parties are involved in the appeal of a number of post-trail motions. ETP cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. Because of the uncertainty of the final determination and the net amount of funds ETP could receive, the Partnership cannot predict whether it will receive any of the damages award ETP may receive. The Partnership is entitled to a portion of that award only to the extent that ETP distributes any of the award to its Common Unitholders. As a result, management cannot yet predict whether ETP will receive any of the damages awarded by this verdict.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (B of A) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
ETP or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of ETP. Once ETP’s management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, ETP accrues the related deductible. As of May 31, 2005 and August 31, 2004, an accrual of $956 and $930, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets.
Environmental
ETP’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although ETP believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, ETP has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has ETP’s operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in the Partnership’s August 31, 2004 balance sheet. Based on information currently available to ETP, such projects are not expected to have a material adverse effect on ETP’s financial condition or results of operations.
In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the EPA) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by Heritage was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). Based upon information currently available to ETP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on ETP’s financial condition or results of operations.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position. As of May 31, 2005 and August 31, 2004, an accrual of $2,020 and $845, respectively, was recorded in ETP’s balance sheet to cover any material environmental liabilities that were not covered by the environmental indemnifications. A receivable of $413 and $423 was recorded in the Partnership’s balance sheets as of May 31, 2005 and August 2004, respectively, to account for Aquila’s share of certain environmental liabilities.
18. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
The Partnership applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Partnership has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At the inception of a hedge, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. The Partnership reclassified into earnings gains of $1,534 and net losses of $9,198 for the three and nine months ended May 31, 2005, respectively, and net losses of $2,766 and net gains of $3,134 for the three and nine months ended May 31, 2004, respectively, related to the commodity financial instruments that were initially recorded in accumulated other comprehensive income (loss). Net losses of $645 and $15,547 attributable to hedge ineffectiveness were recorded in costs of products sold for the three and nine months ended May 31, 2005, respectively, and net gains of $167 and $125 for the three and nine months ended May 31, 2004, respectively. Of the amount on the balance sheet relating to price risk management assets and liabilities in accumulated other comprehensive income, approximately $24,000 is expected to be reclassified into earnings over the next twelve months.
In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contract. Such contracts are exempt from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
The following table details the outstanding derivatives as of May 31, 2005 and August 31, 2004, respectively:
| May 31, 2005: |
Commodity |
Notional Volume |
Maturity |
Fair Value |
|||||||
| MMBTU | |||||||||||
| Basis Swaps IFERC/Nymex |
Gas | 117,304,500 | 2005 | $ | 3,167 | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 55,406,013 | 2006 | (4,198 | ) | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 1,800,000 | 2007 | (277 | ) | ||||||
| $ | (1,308 | ) | |||||||||
| Basis Swaps IFERC/Nymex |
Gas | 160,806,194 | 2005 | $ | (6,739 | ) | |||||
| Basis Swaps IFERC/Nymex |
Gas | 102,855,860 | 2006 | 5,530 | |||||||
| Basis Swaps IFERC/Nymex |
Gas | 15,290,500 | 2007 | 479 | |||||||
| $ | (730 | ) | |||||||||
| Swing Swaps IFERC |
Gas | 148,265,000 | 2005 | $ | 935 | ||||||
| Swing Swaps IFERC |
Gas | 65,150,000 | 2006 | (53 | ) | ||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2007 | — | |||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2008 | — | |||||||
| $ | 882 | ||||||||||
| Swing Swaps IFERC |
Gas | 158,495,000 | 2005 | $ | (41 | ) | |||||
| Swing Swaps IFERC |
Gas | 27,300,000 | 2006 | 133 | |||||||
| $ | 92 | ||||||||||
| Fixed Swaps |
Gas | 3,330,000 | 2005 | $ | 6,129 | ||||||
| Fixed Swaps |
Gas | 3,270,000 | 2006 | 8,919 | |||||||
| $ | 15,048 | ||||||||||
| Futures Nymex |
Gas | 37,652,500 | 2005 | $ | (9,338 | ) | |||||
| Futures Nymex |
Gas | 962,500 | 2006 | 9 | |||||||
| Futures Nymex |
Gas | 240,000 | 2007 | 224 | |||||||
| $ | (9,105 | ) | |||||||||
| Futures Nymex |
Gas | (72,001,000 | ) | 2005 | $ | 14,295 | |||||
| Futures Nymex |
Gas | (8,007,500 | ) | 2006 | (520 | ) | |||||
| $ | 13,775 | ||||||||||
| Options |
Gas | 5,210,000 | 2005 | $ | 6,946 | ||||||
| Options |
Gas | 10,000,000 | 2006 | 18,830 | |||||||
| Options |
Gas | 3,570,000 | 2007 | 8,032 | |||||||
| $ | 33,808 | ||||||||||
| Options |
Gas | (4,978,000 | ) | 2005 | $ | (19 | ) | ||||
| Options |
Gas | (10,730,000 | ) | 2006 | (166 | ) | |||||
| Options |
Gas | (4,300,000 | ) | 2007 | (281 | ) | |||||
| Options |
Gas | (732,000 | ) | 2008 | (406 | ) | |||||
| $ | (872 | ) | |||||||||
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
| May 31, 2005: |
Commodity |
Notional Volume |
Maturity |
Fair Value |
|||||||
| MMBTU | |||||||||||
| Forward Contracts |
Gas | (5,210,000 | ) | 2005 | $ | (6,946 | ) | ||||
| Forward Contracts |
Gas | (10,000,000 | ) | 2006 | (18,830 | ) | |||||
| Forward Contracts |
Gas | (3,570,000 | ) | 2007 | (8,032 | ) | |||||
| $ | (33,808 | ) | |||||||||
| Forward Contracts |
Gas | 4,978,000 | 2005 | $ | 19 | ||||||
| Forward Contracts |
Gas | 10,730,000 | 2006 | 166 | |||||||
| Forward Contracts |
Gas | 4,300,000 | 2007 | 281 | |||||||
| Forward Contracts |
Gas | 732,000 | 2008 | 406 | |||||||
| $ | 872 | ||||||||||
| Barrels |
|||||||||||
| NGL Swaps |
Condensate | 15,000 | 2005 | $ | (179 | ) | |||||
| August 31, 2004: |
MMBTU |
||||||||||
| Basis Swaps IFERC/Nymex |
Gas | 54,472,500 | 2004-2005 | $ | 1,451 | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 62,767,500 | 2004-2005 | 592 | |||||||
| $ | 2,043 | ||||||||||
| Swing Swaps IFERC |
Gas | 119,495,000 | 2004-2005 | $ | 704 | ||||||
| Swing Swaps IFERC |
Gas | 45,265,000 | 2004-2005 | (399 | ) | ||||||
| Swing Swaps IFERC |
Gas | 76,720,000 | 2006-2008 | — | |||||||
| $ | 305 | ||||||||||
| Futures Nymex |
Gas | 10,057,500 | 2004-2005 | $ | (1,311 | ) | |||||
| Futures Nymex |
Gas | 12,677,500 | 2004-2005 | 2,941 | |||||||
| $ | 1,630 | ||||||||||
| Barrels |
|||||||||||
| NGL Swaps |
Condensate Propane, Ethane |
250,000 | 2004-2005 | $ | (86 | ) | |||||
Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions.
Interest Rate Risk
The Partnership is exposed to market risk for changes in interest rates related to its bank credit facilities and the bank credit facilities of ETP. ETP manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements, which allows ETP to effectively convert a portion of variable rate debt into fixed debt.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
On January 6, 2005, ETP entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to the anticipated issuance of $750,000 in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $363 which is recorded in accumulated other comprehensive income. The loss will be amortized over the term of the bonds as interest expense.
ETP also entered into various forward starting interest swaps from February 2005 through May 2005, in anticipation of the issuance of an additional bond offering in the third or fourth fiscal quarter of 2005. Due to certain market conditions, the bond offering was postponed until July 29, 2005. Such agreements were designated as cash flow hedges of an anticipated transaction under SFAS 133. When the forward starting interest swaps settle and the bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. Certain forward starting interest swaps settled during the nine months ended May 31, 2005 with a net $1,384 receipt from the counterparties. Due to the timing of entering into the forward starting interest swaps and the anticipated bond issuance, $363 was recorded as a reduction of interest expense in the nine months ended May 31, 2005. Forward starting interest swaps with a notional amount of $400,000 were outstanding as of May 31, 2005 and had a fair value of $4,233 which was recorded as unrealized losses in accumulated other comprehensive income and a component of price risk management liabilities on the consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the period was a loss of $2,071 and was reclassified from accumulated other comprehensive income and recorded as a component of interest expense during the nine months ended May 31, 2005.
ETP also has an interest rate swap with a notional amount of $75,000 that matures in October 2005. Under the terms of the swap agreement, ETP will pay a fixed rate of 2.76% and will receive three-month LIBOR with a quarterly settlement. The interest rate swap is not accounted for as a hedge but receives mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the consolidated statement of operations.
The following represents gain (loss) on derivative activity for the periods presented:
| Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| Unrealized gain (loss) recognized in cost of products sold related to Partnership’s derivative activity |
$ | (9,732 | ) | $ | 13,451 | |||
| Realized gain included in cost of products sold |
$ | 36,854 | $ | 103 | ||||
| Unrealized gain (loss) on interest rate swap included in interest expense |
$ | (3,009 | ) | $ | — | |||
| Realized loss on interest rate swap included in interest expense |
$ | (3,825 | ) | $ | (1,358 | ) | ||
19. PARTNERS’ CAPITAL:
The ETE partnership agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners in pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, first, such net losses shall be allocated to the Limited Partners in proportion to their respective adjusted capital
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
account balances, as defined by the partnership agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures. The Partnership paid distributions of $63,013 and $247,228 for the nine months ended May 31, 2005 and 2004, respectively.
20. ETP’S QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:
The partnership agreement of ETP requires that ETP will distribute all of its Available Cash to its Unitholders and its general partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s partnership agreement.
Distributions by ETP in an amount equal to 100% of Available Cash will generally be made 98% to the Common, Class D, and Class E Unitholders and 2% to its general partner, ETP GP, subject to the payment of incentive distributions to ETP GP to the extent that certain target levels of cash distributions are achieved.
On October 15, 2004, ETP paid a post-split quarterly distribution of $0.4125 per ETP unit, or $1.65 per unit annually, to its Unitholders of record at the close of business on October 7, 2004. On January 14, 2005, ETP paid a post-split quarterly distribution of $0.4375 per ETP unit, or $1.75 per unit annually, to its Unitholders of record at the close of business on January 5, 2005. On March 16, 2005, ETP announced that it had completed its two-for-one split of its units. On April 14, 2005, ETP paid a post-split quarterly distribution of $0.4625 per unit, or $1.85 per unit annually, an increase of $0.025 per unit per quarter, or $0.10 annually, which on a pre-split basis would have been $0.925 per unit quarterly and $3.70 per unit annually. On June 16, 2005, ETP announced that it had declared a cash distribution for the third quarter ended May 31, 2005 of $0.4875 per Common Unit, or $1.95 per unit annually, an increase of $0.10 per Common Unit on an annualized basis. The distribution was paid on July 15, 2005 to ETP’s Unitholders of record at the close of business on July 8, 2005. In addition to these quarterly distributions, the General Partner of ETP received quarterly distributions for its general partner interest in ETP, and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit post-split. The total amount of distributions declared as of the nine months ended May 31, 2005 on ETP Common Units, ETP Class E, ETP General Partner interests and ETP Incentive Distribution Rights totaled $136,992, $9,363, $3,508, and $25,514, respectively. All such distributions were made from Available Cash from ETP’s Operating Surplus.
21. RELATED PARTY TRANSACTIONS:
Accounts payable to related companies as of May 31, 2005 and August 31, 2004 included approximately $2,387 and $1,400, respectively, payable to unconsolidated affiliates for purchases of natural gas and operating expenses incurred in the normal course of business.
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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
In addition, ETC OLP is a party to various related party transactions. ETC OLP secures compression services from third parties. Energy Transfer Technologies, Ltd. Is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by ETP in conjunction with the January 2004 Energy Transfer Transactions. ETP’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of ETP’s General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. For the nine months ending May 31, 2005, payments totaling $898 were made to the ETG Entities for compression services provided to and utilized in ETC OLP’s operations.
At May 31, 2005, ETP’s natural gas midstream subsidiaries owned a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by one of the General Partner’s directors. ETP is the operator of the Dorado System. At August 31, 2004, there was a balance of $248 owing to ETP by such director of the General Partner for services ETP provided as operator, which was paid in full during the three months ended May 31, 2005.
ET GP, LLC, the general partner of Holdings has a general and administrative services contract to act as an advisor and provide certain general and administrative services to ETE and its affiliates. The general and administrative services that ET GP, LLC provides ETE under this contract include:
| • | General oversight and direction of engineering, accounting, legal and other professional and operational services required for the support, maintenance and operation of the assets used in the Midstream operations, and |
| • | The administration, maintenance and compliance with contractual and regulatory requirements. |
In exchange for these services, ETE and its affiliates are required to pay ET GP, LLC a $500 annual fee payable quarterly and pro-rated for any portion of a calendar year. Pursuant to this contract, ETE and its affiliates were also required to reimburse ET GP, LLC for expenses associated with formation of ETE and is required to indemnify ET GP, LLC, its affiliates, officers and employees for liabilities associated with the actions of ET GP, LLC, its affiliates, officers, and employees. The agreement expressly provides that the fee for the services cannot be paid from funds received by ETP, but only from the Partnership’s funds.
22. SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:
ETP’s Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee the Partnership’s Revolving Credit Facility and Senior Notes. Following are unaudited condensed consolidating financial information of the Partnership, the Issuer (ETP), Guarantor Subsidiaries, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The unaudited condensed consolidating financial information is prepared on the equity method and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.
F-111
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET
As of May 31, 2005
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated | ||||||||||||||
| ASSETS |
|||||||||||||||||||
| CURRENT ASSETS: |
|||||||||||||||||||
| Cash and cash equivalents |
$ | 272 | $ | 1,642 | $ | 4,612 | $ | 15,081 | $ | — | $ | 21,607 | |||||||
| Marketable securities |
— | — | — | 2,658 | — | 2,658 | |||||||||||||
| Accounts receivable, net of allowance for doubtful accounts |
— | 34 | 665,966 | 63,261 | — | 729,261 | |||||||||||||
| Receivable from related companies |
827 | 1,151 | 124,134 | 899 | (126,346 | ) | 665 | ||||||||||||
| Inventories |
— | — | 205,384 | 56,029 | 261,413 | ||||||||||||||
| Other current assets |
— | 281 | 154,316 | 7,744 | — | 162,341 | |||||||||||||
| Total current assets |
1,099 | 3,108 | 1,154,412 | 145,672 | (126,346 | ) | 1,177,945 | ||||||||||||
| PROPERTY, PLANT AND EQUIPMENT, net |
— | 9 | 1,876,122 | 499,136 | 449,105 | 2,824,372 | |||||||||||||
| LONG-TERM PRICE RISK MANAGEMENT ASSETS |
— | — | 18,824 | — | — | 18,824 | |||||||||||||
| INVESTMENT IN AFFILIATES |
424,114 | 2,789,331 | 40,437 | 188,324 | (3,401,349 | ) | 40,857 | ||||||||||||
| GOODWILL |
— | — | 23,736 | 327,584 | — | 351,320 | |||||||||||||
| INTANGIBLES AND OTHER ASSETS, net |
— | 10,116 | 711 | 98,210 | — | 109,037 | |||||||||||||
| Total assets |
$ | 425,213 | $ | 2,802,564 | $ | 3,114,242 | $ | 1,258,926 | $ | (3,078,590 | ) | $ | 4,522,355 | ||||||
| LIABILITIES AND PARTNERS’ CAPITAL |
|||||||||||||||||||
| CURRENT LIABILITIES: |
|||||||||||||||||||
| Accounts payable |
$ | 1 | $ | — | $ | 732,266 | $ | 41,637 | $ | — | $ | 773,904 | |||||||
| Accounts payable to related companies |
222 | 122,665 | 4,734 | 1,836 | (125,885 | ) | 3,572 | ||||||||||||
| Other current liabilities |
1,015 | 25,680 | 126,720 | 51,763 | (461 | ) | 204,717 | ||||||||||||
| Current maturities of long-term debt |
— | — | — | 33,425 | — | 33,425 | |||||||||||||
| Total current liabilities |
1,238 | 148,345 | 863,720 | 128,661 | (126,346 | ) | 1,015,618 | ||||||||||||
| LONG-TERM DEBT, net of discount, less current maturities |
— | 1,220,796 | — | 349,359 | — | 1,570,155 | |||||||||||||
| LONG-TERM PRICE RISK MANAGEMENT LIABILITIES |
— | — | 18,861 | — | 18,861 | ||||||||||||||
| DEFERRED TAXES |
— | — | 53,782 | 60,785 | 104,657 | 219,224 | |||||||||||||
| OTHER NONCURRENT LIABILITIES |
— | — | 16,660 | — | — | 16,660 | |||||||||||||
| MINORITY INTERESTS |
— | — | 15,527 | 1,711 | 1,240,624 | 1,257,862 | |||||||||||||
| 1,238 | 1,369,141 | 968,550 | 540,516 | 1,218,935 | 4,098,380 | ||||||||||||||
| COMMITMENTS AND CONTINGENCIES |
|||||||||||||||||||
| PARTNERS’ CAPITAL |
423,975 | 1,433,423 | 2,145,692 | 718,410 | (4,297,525 | ) | 423,975 | ||||||||||||
| Total liabilities and partners’ capital |
$ | 425,213 | $ | 2,802,564 | $ | 3,114,242 | $ | 1,258,926 | $ | (3,078,590 | ) | $ | 4,522,355 | ||||||
F-112
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET
As of August 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated | ||||||||||||||
| ASSETS |
|||||||||||||||||||
| CURRENT ASSETS: |
|||||||||||||||||||
| Cash and cash equivalents |
$ | 1,101 | $ | 9,506 | $ | 52,054 | $ | 20,191 | $ | — | $ | 82,852 | |||||||
| Marketable securities |
— | — | — | 2,464 | — | 2,464 | |||||||||||||
| Accounts receivable, net of allowance for doubtful accounts |
— | — | 206,023 | 45,323 | — | 251,346 | |||||||||||||
| Other current assets |
2,856 | 2,465 | 91,005 | 57,486 | (8,606 | ) | 145,206 | ||||||||||||
| Total current assets |
3,957 | 11,971 | 349,082 | 125,464 | (8,606 | ) | 481,868 | ||||||||||||
| PROPERTY, PLANT AND EQUIPMENT, net |
— | — | 926,821 | 492,082 | 496,371 | 1,915,274 | |||||||||||||
| INVESTMENT IN AFFILIATES |
364,480 | 989,834 | 7,593 | 182,167 | (1,536,064 | ) | 8,010 | ||||||||||||
| GOODWILL |
— | — | 23,736 | 325,025 | — | 348,761 | |||||||||||||
| INTANGIBLES AND OTHER ASSETS, net |
— | — | 9,610 | 101,668 | — | 111,278 | |||||||||||||
| LONG-TERM AFFILIATED RECEIVABLE |
— | — | 95,000 | — | (95,000 | ) | — | ||||||||||||
| Total assets |
$ | 368,437 | $ | 1,001,805 | $ | 1,411,842 | $ | 1,226,406 | $ | (1,143,299 | ) | $ | 2,865,191 | ||||||
| LIABILITIES AND PARTNERS’ CAPITAL |
|||||||||||||||||||
| CURRENT LIABILITIES: |
|||||||||||||||||||
| Working capital facility |
$ | — | $ | — | $ | — | $ | 14,550 | $ | — | $ | 14,550 | |||||||
| Accounts payable |
— | 715 | 197,897 | 37,019 | — | 235,631 | |||||||||||||
| Other current liabilities |
112 | 3,974 | 62,666 | 65,356 | (8,606 | ) | 123,502 | ||||||||||||
| Current maturities of long-term debt |
— | — | — | 31,234 | — | 31,234 | |||||||||||||
| Total current liabilities |
112 | 4,689 | 260,563 | 148,159 | (8,606 | ) | 404,917 | ||||||||||||
| LONG-TERM DEBT, less current maturities |
— | — | 725,000 | 346,158 | — | 1,071,158 | |||||||||||||
| LONG-TERM AFFILIATED PAYABLE |
— | 95,000 | — | — | (95,000 | ) | — | ||||||||||||
| DEFERRED TAXES |
— | — | 54,436 | 55,460 | 106,830 | 216,726 | |||||||||||||
| MINORITY INTERESTS |
— | — | 1,475 | 801,745 | 803,220 | ||||||||||||||
| OTHER NONCURRENT LIABILITIES |
— | — | 845 | — | — | 845 | |||||||||||||
| 112 | 99,689 | 1,040,844 | 551,252 | 804,969 | 2,496,866 | ||||||||||||||
| COMMITMENTS AND CONTINGENCIES |
|||||||||||||||||||
| PARTNERS’ CAPITAL |
368,325 | 902,116 | 370,998 | 675,154 | (1,948,268 | ) | 368,325 | ||||||||||||
| Total liabilities and partners’ capital |
$ | 368,437 | $ | 1,001,805 | $ | 1,411,842 | $ | 1,226,406 | $ | (1,143,299 | ) | $ | 2,865,191 | ||||||
F-113
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the nine months ended May 31, 2005
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated |
|||||||||||||||||||
| REVENUES: |
||||||||||||||||||||||||
| Midstream and transportation |
$ | — | $ | — | $ | 3,673,730 | $ | — | $ | — | $ | 3,673,730 | ||||||||||||
| Propane |
— | — | — | 604,996 | — | 604,996 | ||||||||||||||||||
| Other |
— | 56 | — | 57,009 | — | 57,065 | ||||||||||||||||||
| Total revenue |
— | 56 | 3,673,730 | 662,005 | — | 4,335,791 | ||||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||
| Cost of products sold |
— | — | 3,359,391 | 396,687 | — | 3,756,078 | ||||||||||||||||||
| Operating expenses |
— | — | 85,947 | 138,175 | — | 224,122 | ||||||||||||||||||
| Depreciation and amortization |
— | — | 27,169 | 39,954 | 9,751 | 76,874 | ||||||||||||||||||
| Selling, general and administrative |
566 | 8,459 | 24,849 | 9,939 | — | 43,813 | ||||||||||||||||||
| Total costs and expenses |
566 | 8,459 | 3,497,356 | 584,755 | 9,751 | 4,100,887 | ||||||||||||||||||
| OPERATING INCOME (LOSS) |
(566 | ) | (8,403 | ) | 176,374 | 77,250 | (9,751 | ) | 234,904 | |||||||||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||||||||||||||
| Interest expense |
(1,080 | ) | (26,498 | ) | (18,432 | ) | (23,325 | ) | 2,985 | (66,350 | ) | |||||||||||||
| Loss on extinguishment of debt |
— | — | (9,550 | ) | — | 3,000 | (6,550 | ) | ||||||||||||||||
| Equity in earnings (losses) of affiliates |
118,723 | 342,937 | (162 | ) | 31,670 | (493,329 | ) | (161 | ) | |||||||||||||||
| Loss on disposal of assets |
— | — | — | (665 | ) | — | (665 | ) | ||||||||||||||||
| Other, net |
4,802 | (206 | ) | 2,012 | (315 | ) | (5,985 | ) | 308 | |||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE |
121,879 | 307,830 | 150,242 | 84,615 | (503,080 | ) | 161,486 | |||||||||||||||||
| Minority interests |
— | — | (397 | ) | (540 | ) | (90,502 | ) | (91,439 | ) | ||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME EXPENSE |
121,879 | 307,830 | 149,845 | 84,075 | (593,582 | ) | 70,047 | |||||||||||||||||
| Income tax expense |
— | (108 | ) | (775 | ) | (6,458 | ) | 2,173 | (5,168 | ) | ||||||||||||||
| INCOME FROM CONTINUING OPERATIONS |
121,879 | 307,722 | 149,070 | 77,617 | (591,409 | ) | 64,879 | |||||||||||||||||
| DISCONTINUED OPERATIONS: |
||||||||||||||||||||||||
| Income from discontinued operations |
— | — | 5,498 | — | — | 5,498 | ||||||||||||||||||
| Gain on sale from discontinued operations, net of income tax expense |
— | — | 143,951 | (1,875 | ) | (37,514 | ) | 104,562 | ||||||||||||||||
| Minority interest on discontinued operations |
— | — | — | — | (53,060 | ) | (53,060 | ) | ||||||||||||||||
| Total income from discontinued operations |
— | — | 149,449 | (1,875 | ) | (90,574 | ) | 57,000 | ||||||||||||||||
| NET INCOME |
$ | 121,879 | $ | 307,722 | $ | 298,519 | $ | 75,742 | $ | (681,983 | ) | $ | 121,879 | |||||||||||
F-114
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the nine months ended May 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated |
|||||||||||||||||||
| REVENUES: |
||||||||||||||||||||||||
| Midstream and transportation |
$ | — | $ | — | $ | 1,314,176 | $ | — | $ | — | $ | 1,314,176 | ||||||||||||
| Propane |
— | — | — | 255,303 | — | 255,303 | ||||||||||||||||||
| Other |
167 | — | — | 22,177 | (167 | ) | 22,177 | |||||||||||||||||
| Total revenue |
167 | — | 1,314,176 | 277,480 | (167 | ) | 1,591,656 | |||||||||||||||||
| COSTS AND EXPENSES: |
||||||||||||||||||||||||
| Cost of products sold |
— | — | 1,194,318 | 151,529 | — | 1,345,847 | ||||||||||||||||||
| Operating expenses |
— | — | 22,840 | 63,782 | — | 86,622 | ||||||||||||||||||
| Depreciation and amortization |
— | — | 11,145 | 17,281 | 4,367 | 32,793 | ||||||||||||||||||
| Selling, general and administrative |
445 | 933 | 13,331 | 4,853 | (167 | ) | 19,395 | |||||||||||||||||
| Total costs and expenses |
445 | 933 | 1,241,634 | 237,445 | 4,200 | 1,484,657 | ||||||||||||||||||
| OPERATING INCOME (LOSS) |
(278 | ) | (933 | ) | 72,542 | 40,035 | (4,367 | ) | 106,999 | |||||||||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||||||||||||||
| Interest expense |
— | (1,473 | ) | (12,233 | ) | (12,897 | ) | 1,492 | (25,111 | ) | ||||||||||||||
| Equity in earnings of affiliates |
29,866 | 88,909 | 419 | 4,663 | (123,351 | ) | 506 | |||||||||||||||||
| Loss on disposal of assets |
— | — | — | (235 | ) | — | (235 | ) | ||||||||||||||||
| Gain on Energy Transfer Transactions |
340,186 | — | — | — | (19,293 | ) | 320,893 | |||||||||||||||||
| Other, net |
— | — | 1,929 | (37 | ) | (1,492 | ) | 400 | ||||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE |
369,774 | 86,503 | 62,657 | 31,529 | (147,011 | ) | 403,452 | |||||||||||||||||
| Minority interests |
— | — | — | (242 | ) | (31,928 | ) | (32,170 | ) | |||||||||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE |
369,774 | 86,503 | 62,657 | 31,287 | (178,939 | ) | 371,282 | |||||||||||||||||
| Income tax expense |
— | (241 | ) | (2,026 | ) | (2,560 | ) | 966 | (3,861 | ) | ||||||||||||||
| INCOME FROM CONTINUING OPERATIONS |
369,774 | 86,262 | 60,631 | 28,727 | (177,973 | ) | 367,421 | |||||||||||||||||
| DISCONTINUED OPERATIONS |
||||||||||||||||||||||||
| Income from discontinued operations |
— | — | 4,129 | — | — | 4,129 | ||||||||||||||||||
| Minority interest on discontinued operations |
— | — | — | — | (1,776 | ) | (1,776 | ) | ||||||||||||||||
| Total income from discontinued operations |
4,129 | (1,776 | ) | 2,353 | ||||||||||||||||||||
| NET INCOME |
$ | 369,774 | $ | 86,262 | $ | 64,760 | $ | 28,727 | $ | (179,749 | ) | $ | 369,774 | |||||||||||
F-115
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended May 31, 2005
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Consolidation Adjustments |
Consolidated |
|||||||||||||||||||
| NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES: |
$ | 6,312 | $ | (8,400 | ) | $ | 245,847 | $ | 58,338 | $ | (85,238 | ) | $ | 216,859 | ||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||||||
| Cash paid for acquisitions, net of cash acquired |
— | — | (1,103,989 | ) | (13,875 | ) | — | (1,117,864 | ) | |||||||||||||||
| Cash invested in subsidiaries |
— | (1,613,195 | ) | (51 | ) | (7,194 | ) | 1,620,389 | (51 | ) | ||||||||||||||
| Capital expenditures |
— | (9 | ) | (85,893 | ) | (32,675 | ) | — | (118,577 | ) | ||||||||||||||
| Proceeds from sale of subsidiary units |
2,631 | — | — | — | — | 2,631 | ||||||||||||||||||
| Proceeds from the sale of discontinued operations |
— | — | 191,606 | — | — | 191,606 | ||||||||||||||||||
| Proceeds from the sale of assets |
— | — | 132 | 3,478 | — | 3,610 | ||||||||||||||||||
| Net cash used in investing activities |
2,631 | (1,613,204 | ) | (998,195 | ) | (50,266 | ) | 1,620,389 | (1,038,645 | ) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||||||
| Proceeds from borrowings |
200,000 | 1,849,000 | 80,000 | 142,393 | — | 2,271,393 | ||||||||||||||||||
| Principal payments on debt |
(200,000 | ) | (626,000 | ) | (805,000 | ) | (152,701 | ) | — | (1,783,701 | ) | |||||||||||||
| Advances from (to) related parties |
(174,624 | ) | 403,348 | 559,591 | — | (788,315 | ) | — | ||||||||||||||||
| Principal payments received from affiliates |
174,624 | (384,967 | ) | (577,972 | ) | — | 788,315 | — | ||||||||||||||||
| Proceeds from equity offering |
— | 349,749 | — | — | — | 349,749 | ||||||||||||||||||
| Capital contributions |
— | 7,194 | 1,613,195 | — | (1,620,389 | ) | — | |||||||||||||||||
| Distributions to parent |
— | (62,268 | ) | (161,799 | ) | (31,521 | ) | 255,588 | — | |||||||||||||||
| Distribution from subsidiaries |
54,286 | 171,991 | — | 28,646 | (254,923 | ) | — | |||||||||||||||||
| Unit distributions |
(63,013 | ) | (81,464 | ) | — | — | 81,464 | (63,013 | ) | |||||||||||||||
| Debt issuance costs |
— | (12,842 | ) | (3,109 | ) | — | 3,109 | (12,842 | ) | |||||||||||||||
| Redemption and retirement of Employee Interests |
(1,045 | ) | — | — | — | — | (1,045 | ) | ||||||||||||||||
| Net cash provided by (used in) financing activities |
(9,772 | ) | 1,613,741 | 704,906 | (13,183 | ) | (1,535,151 | ) | 760,541 | |||||||||||||||
| DECREASE IN CASH AND CASH EQUIVALENTS |
(829 | ) | (7,863 | ) | (47,442 | ) | (5,111 | ) | — | (61,245 | ) | |||||||||||||
| CASH AND CASH EQUIVALENTS, beginning of period |
1,101 | 9,506 | 52,054 | 20,191 | — | 82,852 | ||||||||||||||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 272 | $ | 1,643 | $ | 4,612 | $ | 15,080 | $ | — | $ | 21,607 | ||||||||||||
F-116
Table of Contents
Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended May 31, 2004
(In thousands)
| Parent |
Issuing Subsidiary |
Guarantor Subsidiaries |
Non-Guarantor Subsidiaries |
Eliminations |
Consolidated |
|||||||||||||||||||
| NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES |
$ | (612 | ) | $ | (531 | ) | $ | 100,015 | $ | 54,189 | $ | (17,881 | ) | $ | 135,180 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||||||
| Cash paid for acquisitions, net of cash acquired |
(30,000 | ) | (191,207 | ) | — | (14,920 | ) | 113,728 | (122,399 | ) | ||||||||||||||
| Investments in unconsolidated subsidiaries |
(15,540 | ) | (230,000 | ) | (250 | ) | (15,540 | ) | 261,080 | (250 | ) | |||||||||||||
| Proceeds from sale of investment in subsidiary |
88,906 | — | — | — | (88,906 | ) | — | |||||||||||||||||
| Capital expenditures |
— | — | (78,572 | ) | (9,689 | ) | — | (88,261 | ) | |||||||||||||||
| Proceeds from the sale of assets |
— | — | 2 | 629 | — | 631 | ||||||||||||||||||
| Net cash used in investing activities |
43,366 | (421,207 | ) | (78,820 | ) | (39,520 | ) | 285,902 | (210,279 | ) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||||||
| Proceeds from borrowings |
— | 101,693 | 325,000 | 39,238 | (101,693 | ) | 364,238 | |||||||||||||||||
| Principal payments on debt |
— | — | (226,000 | ) | (134,659 | ) | — | (360,659 | ) | |||||||||||||||
| Long term loan to related party |
— | — | (101,693 | ) | — | 101,693 | — | |||||||||||||||||
| Capital contributions |
— | 15,540 | 180,000 | 65,540 | (261,080 | ) | — | |||||||||||||||||
| Distributions to parent |
— | (8,987 | ) | (196,708 | ) | (853 | ) | 206,548 | — | |||||||||||||||
| Unit distributions |
(247,228 | ) | (17,881 | ) | — | — | 17,881 | (247,228 | ) | |||||||||||||||
| Distributions from subsidiaries |
205,695 | 853 | (206,548 | ) | — | |||||||||||||||||||
| Debt issuance costs |
— | — | (4,236 | ) | — | — | (4,236 | ) | ||||||||||||||||
| Equity offering |
— | 334,330 | — | — | — | 334,330 | ||||||||||||||||||
| Net cash provided by (used in) financing activities |
(41,533 | ) | 424,695 | (23,637 | ) | (29,881 | ) | (243,199 | ) | 86,445 | ||||||||||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
1,221 | 2,957 | (2,442 | ) | (15,212 | ) | 24,822 | 11,346 | ||||||||||||||||
| CASH AND CASH EQUIVALENTS, beginning of period |
1,950 | — | 53,122 | 24,823 | (24,822 | ) | 55,073 | |||||||||||||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 3,171 | $ | 2,957 | $ | 50,680 | $ | 9,611 | $ | — | $ | 66,419 | ||||||||||||
F-117
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
23. REPORTABLE SEGMENTS:
The Partnership’s financial statements reflect five reportable segments, as reported by ETP:
ETC OLP:
| • | midstream operations |
| • | transportation and storage operations |
HOLP:
| • | retail propane operations |
| • | domestic wholesale propane operations |
| • | foreign wholesale propane operations of MP Energy Partnership |
Segments below the quantitative thresholds are classified as “other”. None of these segments have ever met any of the quantitative thresholds for determining reportable segments. As a result of the HPL acquisition, we have redefined the transportation operations to transportation and storage operations.
Midstream and transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
The midstream operations focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through ETP’s pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices. The transportation and storage operations focus on transporting natural gas through ETP’s Oasis Pipeline, ET Fuel System, East Texas Pipeline System, and HPL System. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. The transportation and storage operations also consist of the HPL System which generates its revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows ETP to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.
ETP’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. ETP manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies. The Partnership evaluates the performance of its operating segments based on operating income exclusive of general partnership selling, general, and administrative expenses of $9,362 and $1,378 for the nine months ended May 31, 2005 and May 31, 2004, respectively.
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
Investment in affiliates and equity in earnings (losses) of affiliates relate primarily to ETP’s investments in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd, and MidTexas which are included in our midstream segment and transportation and storage segments. The following table presents the unaudited financial information by segment for the following periods:
| For the Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| Volumes: |
||||||||
| Midstream |
||||||||
| Natural gas MMBtu/d—sold |
1,594,780 | 982,314 | ||||||
| NGLs Bbls/d—sold |
13,194 | 7,375 | ||||||
| Transportation and storage |
||||||||
| Natural gas MMBtu/d—sold |
1,660,567 | — | ||||||
| Natural gas MMBtu/d—transported |
3,214,842 | 905,284 | ||||||
| NGLs Bbls/d—sold/d |
2,273 | — | ||||||
| Propane gallons |
||||||||
| (in thousands) |
||||||||
| Retail |
346,156 | 166,099 | ||||||
| Domestic wholesale |
9,414 | 3,824 | ||||||
| Foreign wholesale |
||||||||
| Affiliated |
85,558 | 35,457 | ||||||
| Unaffiliated |
50,293 | 22,337 | ||||||
| Elimination |
(85,558 | ) | (35,457 | ) | ||||
| Total gallons |
405,863 | 192,260 | ||||||
| Revenues: |
||||||||
| Midstream |
$ | 2,676,611 | $ | 1,277,349 | ||||
| Transportation and storage |
1,460,303 | 58,509 | ||||||
| Retail propane and other propane related |
599,241 | 255,282 | ||||||
| Domestic wholesale propane |
10,466 | 3,163 | ||||||
| Foreign wholesale propane |
||||||||
| Affiliated |
76,347 | 11,334 | ||||||
| Unaffiliated |
47,514 | 16,758 | ||||||
| Other |
4,840 | 2,277 | ||||||
| Eliminations |
(539,531 | ) | (33,016 | ) | ||||
| Total |
$ | 4,335,791 | $ | 1,591,656 | ||||
F-119
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
| For the Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| Cost of Sales: |
||||||||
| Midstream |
$ | 2,592,209 | $ | 1,208,986 | ||||
| Transportation and storage |
1,230,366 | 7,013 | ||||||
| Retail propane and other propane related |
341,129 | 132,798 | ||||||
| Domestic wholesale propane |
9,493 | 2,681 | ||||||
| Foreign wholesale propane |
44,838 | 15,560 | ||||||
| Other |
1,227 | 490 | ||||||
| Eliminations |
(463,184 | ) | (21,681 | ) | ||||
| Total |
$ | 3,756,078 | $ | 1,345,847 | ||||
| Operating Income (Loss): |
||||||||
| Midstream |
$ | 49,134 | $ | 42,958 | ||||
| Transportation and storage |
117,490 | 25,382 | ||||||
| Retail propane and other propane related |
77,814 | 40,103 | ||||||
| Domestic wholesale propane |
(1,902 | ) | (890 | ) | ||||
| Foreign wholesale propane |
||||||||
| Affiliated |
605 | 169 | ||||||
| Unaffiliated |
1,401 | 645 | ||||||
| Elimination |
(605 | ) | (169 | ) | ||||
| Other |
330 | 179 | ||||||
| Selling, general and administrative expenses not allocated to segments |
(9,362 | ) | (1,378 | ) | ||||
| Total |
$ | 234,905 | $ | 106,999 | ||||
| Income from discontinued operations, net of income tax expense and minority interest: |
||||||||
| Midstream |
$ | 57,000 | $ | 2,353 | ||||
| Gain (loss) on disposal of assets: |
||||||||
| Midstream |
$ | — | $ | — | ||||
| Transportation and storage |
— | — | ||||||
| Retail propane |
(619 | ) | (245 | ) | ||||
| Domestic wholesale propane |
25 | 10 | ||||||
| Other |
(71 | ) | — | |||||
| Total |
$ | (665 | ) | $ | (235 | ) | ||
| Minority interest expense: |
||||||||
| Midstream |
$ | — | $ | — | ||||
| Transportation and storage |
397 | — | ||||||
| Foreign wholesale propane |
540 | 242 | ||||||
| Other |
90,502 | 31,928 | ||||||
| Total |
$ | 91,439 | $ | 32,170 | ||||
F-120
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
| For the Nine Months Ended |
||||||||
| May 31, 2005 |
May 31, 2004 |
|||||||
| Depreciation and amortization: |
||||||||
| Midstream |
$ | 12,573 | $ | 8,895 | ||||
| Transportation and storage |
24,347 | 6,617 | ||||||
| Retail propane |
39,135 | 16,920 | ||||||
| Domestic wholesale propane |
514 | 249 | ||||||
| Foreign wholesale propane |
20 | 9 | ||||||
| Other |
285 | 103 | ||||||
| Total |
$ | 76,874 | $ | 32,793 | ||||
| Interest expense: |
||||||||
| Midstream |
$ | 15,501 | $ | 11,473 | ||||
| Transportation and storage |
5,120 | 5,359 | ||||||
| Retail propane |
23,299 | 12,881 | ||||||
| Other |
26,136 | (3 | ) | |||||
| Eliminations |
(3,706 | ) | (4,599 | ) | ||||
| Total |
$ | 66,350 | $ | 25,111 | ||||
| Earnings (losses) from equity investments: |
||||||||
| Midstream |
$ | 207 | $ | 419 | ||||
| Transportation and storage |
(369 | ) | — | |||||
| Foreign wholesale |
1 | 87 | ||||||
| Total |
$ | (161 | ) | $ | 506 | |||
| Income tax expense (benefit) on continuing operations: |
||||||||
| Midstream |
$ | 33 | $ | — | ||||
| Transportation and storage |
(1,431 | ) | 1,039 | |||||
| Other |
6,566 | 2,822 | ||||||
| Total |
$ | 5,168 | $ | 3,861 | ||||
| May 31, 2005 |
August 31, 2004 |
|||||||
| Total Assets: |
||||||||
| Midstream |
$ | 897,300 | $ | 721,009 | ||||
| Transportation and storage |
2,542,256 | 1,090,983 | ||||||
| Retail propane and other propane related |
1,010,712 | 956,021 | ||||||
| Domestic wholesale propane |
8,613 | 12,567 | ||||||
| Foreign wholesale propane |
13,553 | 10,034 | ||||||
| Other |
49,921 | 74,577 | ||||||
| Total |
$ | 4,522,355 | $ | 2,865,191 | ||||
F-121
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Index to Financial Statements
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(unaudited)
24. SUPPLEMENTAL INFORMATION:
Following is the balance sheet of the Partnership which is included to provide additional information with respect to the Partnership’s financial position on a stand-alone basis.
| May 31, 2005 |
August 31, 2004 | |||||
| ASSETS |
||||||
| CURRENT ASSETS: |
||||||
| Cash and cash equivalents |
$ | 272 | $ | 1,101 | ||
| Accounts receivable from related companies |
827 | 2,857 | ||||
| Total current assets |
1,099 | 3,958 | ||||
| INVESTMENT IN AFFILIATES |
424,114 | 364,479 | ||||
| Total assets |
$ | 425,213 | $ | 368,437 | ||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||
| CURRENT LIABILITIES: |
||||||
| Accounts payable |
1 | — | ||||
| Accounts payable to affiliate |
222 | 87 | ||||
| Accrued and other current liabilities |
1,015 | 25 | ||||
| Total current liabilities |
1,238 | 112 | ||||
| PARTNERS’ CAPITAL: |
||||||
| General Partner’s capital |
4,550 | 4,053 | ||||
| Limited Partners’ capital |
413,464 | 364,261 | ||||
| Accumulated other comprehensive income |
5,961 | 11 | ||||
| Total partners’ capital |
423,975 | 368,325 | ||||
| Total liabilities and partners’ capital |
$ | 425,213 | $ | 368,437 | ||
25. SUBSEQUENT EVENTS:
On July 26, 2005, ETP completed the sale of 3,000,000 common units in a private sale to an institutional investor. The common units were issued pursuant to ETP’s effective shelf registration statement and the proceeds of $105.6 million were used by ETP to retire a portion of the outstanding indebtness on its revolving credit facility and to fund ETP’s recently announced capital expansion projects.
ETP also entered into a long-term agreement in July, 2005 with XTO Energy Inc. to transport minimum annual volumes over a ten-year term on pipelines to be constructed by the Partnership. XTO will also be entitled to transport additional volumes under similar terms. The newly constructed pipelines will consist of 264 miles of 30 inch, 36 inch and 42 inch pipelines while adding approximately 40,000 horsepower of compression. The estimated cost of the pipeline construction project is estimated to be approximately $454,000.
F-122
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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Members
LE GP, LLC
We have audited the accompanying consolidated balance sheet of LE GP, LLC and subsidiaries as of August 31, 2004. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal controls as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.
In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of LE GP, LLC and subsidiaries as of August 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Tulsa, Oklahoma
September 1, 2005
F-123
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Index to Financial Statements
CONSOLIDATED BALANCE SHEET
(in thousands)
| August 31, 2004 | |||
| ASSETS |
|||
| CURRENT ASSETS: |
|||
| Cash and cash equivalents |
$ | 82,859 | |
| Marketable securities |
2,464 | ||
| Accounts receivable, net of allowance for doubtful accounts |
251,346 | ||
| Accounts receivable from related companies |
35 | ||
| Inventories |
53,261 | ||
| Deposits paid to vendors |
3,023 | ||
| Exchanges receivable |
8,640 | ||
| Price risk management asset |
4,615 | ||
| Prepaid expenses and other |
7,724 | ||
| Assets held for sale, net |
67,908 | ||
| Total current assets |
481,875 | ||
| PROPERTY, PLANT AND EQUIPMENT, net |
1,915,274 | ||
| INVESTMENT IN AFFILIATES |
8,010 | ||
| GOODWILL |
348,761 | ||
| INTANGIBLES AND OTHER ASSETS, net |
111,278 | ||
| Total assets |
$ | 2,865,198 | |
| LIABILITIES AND MEMBER’S EQUITY |
|||
| CURRENT LIABILITIES: |
|||
| Working capital facility |
$ | 14,550 | |
| Accounts payable |
235,631 | ||
| Accounts payable to related companies |
1,507 | ||
| Exchanges payable |
12,751 | ||
| Customer deposits |
11,378 | ||
| Liabilities from discontinued operations |
20,590 | ||
| Accrued and other current liabilities |
73,762 | ||
| Price risk management liabilities |
1,262 | ||
| Income taxes payable |
2,252 | ||
| Current maturities of long-term debt |
31,234 | ||
| Total current liabilities |
404,917 | ||
| LONG-TERM DEBT, less current maturities |
1,071,158 | ||
| OTHER NON-CURRENT LIABILITIES |
845 | ||
| MINORITY INTERESTS |
1,167,551 | ||
| DEFERRED TAXES |
216,726 | ||
| 2,861,197 | |||
| COMMITMENTS AND CONTINGENCIES |
|||
| MEMBERS’ EQUITY: |
4,001 | ||
| Total liabilities and members’ equity |
$ | 2,865,198 | |
The accompanying notes are an integral part of this consolidated balance sheet.
F-124
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Index to Financial Statements
NOTES TO CONSOLIDATED BALANCE SHEET
AUGUST 31, 2004
(Dollars in thousands)
1. OPERATIONS AND ORGANIZATION:
LE GP, LLC (the Company) is the general partner of Energy Transfer Equity, L.P. (“ETE”). As of August 31, 2004, ETE directly or indirectly owned all of the equity interests in Energy Transfer Partners GP, L.P. (“ETP GP”), and 15,833,234 Common Units of Energy Transfer Partners, L.P. (“ETP”) which entitled ETE to receive all of the cash distributions made by ETP GP related to its general partner interest and the related incentive distribution rights and cash distributions made by ETP related to ETP’s Common Units.
LE GP, LLC is a Texas limited liability company controlled by common ownership of ETC Holdings, LP (“Holdings”). On August 23, 2005, the Partnership converted from a Texas limited liability company to a Delaware limited liability company. LE GP, LLC and the general partner of Holdings are ultimately owned and controlled by the Co-CEOs of ETP, and Natural Gas Partners, a venture capital investor. The Company owns a 0.01% general partner interest in ETE which entitles it to receive all of the cash distributions made by ETE related to this general partner interest. These distributions are the Company’s primary source of cash flow.
In September 2004, the Partnership sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, the Partnership sold a 5% limited partner interest in ETE to this group. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were contributed together with the 4.6662% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interests together were deemed to be an equivalent value of the 5% limited partner interest in ETE. The equivalent value was determined to be the book value of the Common Units and the interests in ETP GP and ETP LLC that were contributed.
Energy Transfer Transactions
On January 20, 2004, ETE and Heritage completed a series of transactions whereby ETE contributed ETC OLP to Heritage in exchange for cash of $300,000 less the amount of ETC OLP debt in excess of $151,500, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by ETE relating to the ETC OLP business prior to closing, $433,909 of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151,500. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivable to ETE and an affiliate of ETE contributed an office building to ETC OLP. ETE also received 7,485,030 Special Units of Heritage on a post-split basis as consideration for the project ETC OLP had in progress to construct the Bossier Pipeline. The Special Units converted to ETP.’s (formerly Heritage) Common Units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the Special Units to Common Units was approved by ETP’s Unitholders at a special meeting held on June 23, 2004.
Simultaneously with the Energy Transfer Transactions, ETE obtained control of Heritage by acquiring all of the interest in ETP GP, the General Partner of Heritage, and ETP LLC, the general partner of ETP GP, from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30,000 (the General Partner Transaction). In conjunction with the General Partner Transaction, ETP GP contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (HOLP) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) from ETP GP for $100,000.
F-125
Table of Contents
Index to Financial Statements
LE GP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325,000 from financial institutions and Heritage raised $355,948 of gross proceeds through the sale of 9,200,000 Common Units of Heritage at an offering price of $38.69 per unit. The net proceeds were used to finance the transactions and for general company purposes.
Subsequent to the Energy Transfer Transactions, Heritage changed its name to Energy Transfer Partners, L.P.
Accounting Treatment of the Energy Transfer Transactions
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards 141, Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquirer for accounting purposes. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by ETE through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%, determined in accordance with Emerging Issues Task Force (EITF) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141. The assets and liabilities of ETC OLP have remained at their historical cost.
The acquisition of HHI by Heritage was accounted for as a capital transaction as the primary asset held by HHI was 4,426,916 Common Units of ETP on a pre-split basis. Following the acquisition of HHI, the ETP Common Units held by HHI were converted to Class E Units of Heritage. Following ETP’s two-for-one split completed on March 15, 2005, there are 8,853,832 ETP Class E Units outstanding, all owned by HHI.
The issuance of the additional ETP Common Units upon the conversion of ETP Special Units adjusted the percent of Heritage acquired by ETE in the Energy Transfer Transactions and resulted in an additional fair value step-up being recorded in accordance with EITF 90-13. Upon the conversion of the Special Units on June 23, 2004, ETE acquired approximately 41.5% of Heritage.
The excess purchase price over Heritage’s cost was determined as follows:
| Net book value of Heritage at January 20, 2004 |
$ | 239,102 | ||
| Historical goodwill at January 20, 2004 |
(170,500 | ) | ||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 267,210 | ||||
| Percent of Heritage acquired by La Grange Energy |
41.5 | % | ||
| Equity interest acquired |
$ | 110,892 | ||
| Fair market value of Limited Partner Units |
668,534 | |||
| Purchase price of General Partner Interest |
30,000 | |||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 897,142 | ||||
| Percent of Heritage acquired by La Grange Energy |
41.5 | % | ||
| Fair value of equity acquired |
372,314 | |||
| Net book value of equity acquired |
110,892 | |||
| Excess purchase price over Heritage cost |
$ | 261,422 | ||
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Index to Financial Statements
LE GP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
The excess purchase price over Heritage cost was allocated as follows:
| Property, plant and equipment (25 year life) |
$ | 35,269 | |
| Customer lists (15 year life) |
18,926 | ||
| Trademarks |
19,251 | ||
| Goodwill |
187,976 | ||
| $ | 261,422 | ||
Goodwill was warranted in the Energy Transfer Transactions because the business enterprise value of the operations acquired exceeded the fair market value of the tangible and identifiable intangible assets acquired. The allocation of the purchase price reflects the final assessment of asset values of Heritage acquired in the Energy Transfer Transactions.
The gain recognized by ETE as a result of the Energy Transfer Transaction was determined as follows:
| ETE’s historical basis in ETC OLP |
$ | (90,906 | ) | |
| Percent sold in Energy Transfer Transactions |
58.5 | % | ||
| (53,180 | ) | |||
| Fair value of Heritage equity acquired in Energy Transfer Transactions |
372,314 | |||
| Less: Consideration paid for ETP’s GP interest |
$ | (30,000 | ) | |
| Fair value of assets received in Energy Transfer Transactions |
$ | 342,314 | ||
| Gain on partial sale of ETC OLP |
$ | 395,494 | ||
The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE in the Energy Transfer Transactions of approximately 58.5%, determined in accordance with Emerging Issues Task Force EITF 90-13 and SFAS 141. The step up resulted in an approximate $504,000 increase to property, plant and equipment at ETE which is being depreciated over estimated lives 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributable to a taxable entity of ETC OLP, resulting in approximately $108.5 million of deferred taxes recorded by ETE. The deferred taxes will reverse at the same rate as the related step-up in assets will be depreciated.
Accounting Treatment of the General Partner Transaction
Goodwill of $29,589 was recorded in connection with ETE’s acquisition of ETP GP. Goodwill was warranted because, as the General Partner of ETP, ETP GP owns certain incentive distribution rights, which entitle it to receive distributions in excess of its 2% general partner interest in ETP.
Business Operations
Subsequent to the Energy Transfer Transactions described above, LE GP LLC conducts business operations only through the two wholly owned operating partnerships of ETP, ETC OLP and HOLP (collectively the Operating Partnerships).
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NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
ETC OLP is engaged in midstream natural gas and transportation operations. ETC OLP owns and operates natural gas gathering, natural gas intrastate pipeline systems, and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and Louisiana. ETC OLP is a Texas limited partnership formed in October 2002 and was 99.9% owned by ETE prior to the Energy Transfer Transactions and is 99.9% owned by ETP subsequent to the Energy Transfer Transactions and 0.1% owned by ETC OLP’s general partner LA GP, LLC, a wholly-owned subsidiary of ETP. ETC OLP is the 99.9% limited partner to ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Oklahoma Pipeline Ltd, which was sold on April 14, 2005, ETC Katy Pipeline, Ltd., ETC Processing, Ltd. and ETC Marketing, Ltd. and the 99% limited partner to ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. ETC OLP also owns a 50% interest in Vantex Gas Pipeline Company, LLC, a 50.5% interest in Vantex Energy Services, Ltd., and a 49% interest in Ranger Pipeline, L.P. These investments are accounted for under the equity method of accounting as ETC OLP exercises significant influence over these entities but lacks controlling interests. Effective June 29, 2005, ETP bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd.
As of August 31, 2004, ETC OLP owned and operated approximately 5,950 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 4.7 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Its major asset groups consist of the Southeast Texas System, Elk City System, Oasis Pipeline, East Texas Pipeline and the former TUFCO System which is referred to as the ET Fuel System.
HOLP, a Delaware limited partnership is engaged in retail and wholesale propane operations. As of August 31, 2004, HOLP sold propane and propane-related products to more than 650,000 active residential, commercial, industrial, and agricultural customers in 32 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership is a Canadian partnership, in which HOLP owns a 60% interest, engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly owned subsidiary, Heritage Energy Resources, L.L.C.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Principles of Consolidation
At August 31, 2004 the consolidated balance sheet of the Company includes the accounts of ETE and subsidiaries which include ETP GP, ETP LLC, ETP, ETC OLP, HOLP, and HHI, A minority interest liability is recorded for all partially owned subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. The Company considers cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Marketable Securities
Marketable securities owned by ETP and its subsidiaries are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at their fair values.
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AUGUST 31, 2004
(Dollars in thousands)
Accounts Receivable
ETC OLP’s midstream and transportation operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). ETP’s management reviews midstream and transportation accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation operations. ETP’s management believes that the occurrence of bad debt in ETC OLP’s midstream and transportation operations is not significant; therefore, an allowance for doubtful accounts for the midstream and transportation segments was not deemed necessary at August 31, 2004.
ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due.
HOLP grants credit to its customers for the purchase of propane and propane-related products. Also included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane and liquids marketing activities are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane and liquids marketing segments is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of ETP’s customers and any specific disputes. Accounts receivable consisted of the following:
| Accounts receivable midstream and transportation |
$ | 206,023 | ||
| Accounts receivable propane |
46,990 | |||
| Less—allowance for doubtful accounts |
(1,667 | ) | ||
| Total, net |
$ | 251,346 | ||
Inventories
Midstream and transportation inventories are valued at market prices. These amounts turn over monthly and management believes the costs approximate market value. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following at August 31, 2004:
| Natural gas, propane and other NGLs |
$ | 40,926 | |
| Appliances, parts and fittings and other |
12,335 | ||
| Total inventories |
$ | 53,261 | |
Deposits
Deposits are paid to vendors in the midstream and transportation business as prepayments for natural gas deliveries in the following month. ETP makes prepayments when the volume of business with a vendor exceeds ETP’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $3,000 as of August 31, 2004. ETP also has deposits with derivative counterparties of $23 as of August 31, 2004.
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AUGUST 31, 2004
(Dollars in thousands)
Deposits are received from ETP’s midstream and transportation customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane use. Prepayments and security deposits may also be required when ETP’s customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $11,378 as of August 31, 2004.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on the Company’s consolidated balance sheet. Management believes market value approximates cost.
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Company capitalizes certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.
ETP reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, ETP reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the periods presented.
Components and useful lives of property, plant and equipment were as follows at August 31, 2004:
| Land and improvements |
$ | 28,156 | ||
| Buildings and improvements (10 to 30 years) |
37,201 | |||
| Pipelines and equipment (10 to 65 years) |
1,279,755 | |||
| Natural gas storage (40 years) |
24,277 | |||
| Bulk storage, equipment and facilities (3 to 30 years) |
52,007 | |||
| Tanks and other equipment (5 to 30 years) |
321,511 | |||
| Vehicles (5 to 10 years) |
56,740 | |||
| Right of way (20 to 65 years) |
65,924 | |||
| Furniture and fixtures (3 to 10 years) |
7,324 | |||
| Linepack |
12,802 | |||
| Pad Gas |
42,136 | |||
| Other (5 to 10 years) |
5,581 | |||
| 1,933,414 | ||||
| Less—Accumulated depreciation |
(61,051 | ) | ||
| 1,872,363 | ||||
| Plus—Construction work-in-process |
42,911 | |||
| Property, plant and equipment, net |
$ | 1,915,274 | ||
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AUGUST 31, 2004
(Dollars in thousands)
Asset Retirement Obligation
ETP accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, (SFAS 143). SFAS No. 143 requires ETP to record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, an entity would recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.
ETP’s management has completed the assessment of SFAS 143, and has determined that ETP is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2004 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.
Investment in Affiliates
ETC OLP owns a 50% interest in Vantex Gas Pipeline Company, LLC, and a 50.5% interest in Vantex Energy Services, Ltd. The Partnership accounts for these investments under the equity method of accounting. The Vantex system is located in East Texas and is composed of approximately 250 miles of pipeline. Vantex Energy Services provides energy related marketing services to small and medium sized producers and end users on the Vantex Gas Pipeline system.
ETC OLP also owns a 49% interest in Ranger Pipeline, L.P. (Ranger), which owns a 50% interest in Mountain Creek Joint Venture (Mountain Creek). Mountain Creek is located in North Texas and is composed of approximately 15 miles of pipeline. Mountain Creek supplies gas to an electric generation plant and earns the majority of its yearly income between the months of June and October. The Partnership accounts for its investment in Ranger using the equity method of accounting.
Goodwill
The Company assesses the impairment of its goodwill in accordance with Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”), by determining whether the carrying amount exceeds the fair value of the recognized goodwill asset. If impairment has occurred, the difference between the carrying amount and the fair value is recognized as a loss in the consolidated statements of operations in the period of the impairment. Based on the annual impairment tests performed, there was no impairment as of August 31, 2004.
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(Dollars in thousands)
Intangibles and Other Assets
Intangibles and other assets are stated at cost net of amortization computed on the straight-line method. The Company eliminates from its balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other assets as of August 31, 2004 were as follows:
| Gross Carrying Amount |
Accumulated Amortization |
||||||
| Amortized intangible assets— |
|||||||
| Noncompete agreements (5 to 15 years) |
$ | 27,952 | $ | (3,006 | ) | ||
| Customer lists (15 years) |
46,691 | (2,307 | ) | ||||
| Financing costs (3 to 15 years) |
18,125 | (5,515 | ) | ||||
| Consulting agreements (2 to 7 years) |
132 | (29 | ) | ||||
| Other (10 years) |
477 | (143 | ) | ||||
| Total |
93,377 | (11,000 | ) | ||||
| Unamortized intangible assets— |
|||||||
| Trademarks |
26,818 | — | |||||
| Other assets |
2,083 | — | |||||
| Total intangibles and other assets |
$ | 122,278 | $ | (11,000 | ) | ||
The Company reviews other intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of other intangible assets is not recoverable, the Company reduces the carrying amount of such assets to fair value.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following as of August 31, 2004:
| Interest payable |
$ | 6,633 | |
| Wages, payroll taxes and employee benefits |
15,975 | ||
| Deferred tank rent |
4,581 | ||
| Taxes other than income |
6,921 | ||
| Advanced budget payments and unearned revenue |
33,299 | ||
| Other |
6,353 | ||
| Accrued and other current liabilities |
$ | 73,762 | |
Fair Value
The carrying amounts of accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to the Company for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2004 was $1,128,536 and $1,102,393 respectively.
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NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
Income Taxes
LE GP, LLC is a limited liability company that is treated as a partnership for federal income tax purposes. As a result, LE GP, LLC’s earnings or losses for income tax purposes are included in the tax returns of the individual members. Oasis, Heritage Holdings, and certain other of the Company’s subsidiaries are taxable corporations and follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.
Employee Incentive Interests
ETE’s partnership agreement as amended and restated provides for certain incentive interests for certain employees. The employee incentive interests consists of 12,145,749 Employee Incentive Units granted to certain employees on the formation of ETE (the “Employee Incentive Units”).
The Employee Incentive Units vest ratably over a three-year period from the date of grant or fully vest upon the occurrence of a Fundamental Change as defined in ETE’s partnership agreement. Employees must forfeit all vested and unvested Employee Incentive Units when the employee voluntarily terminates his or her employment or is terminated with cause as defined in ETE’s partnership agreement. The Employee Incentive Units granted shall be forfeited upon the fifth anniversary of the grant if the required “Tier I Payout,” as defined in ETE’s partnership agreement, has not yet occurred.
The Partnership accounts for the Employee Incentive Interests in accordance with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123). Under SFAS 123, total compensation is measured at the fair value of the award on the grant date and compensation expense is recorded ratably over the service period. Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive until vesting of the Employee Incentive Interests.
As a result of The Energy Transfer Transactions in January 2004, all Employee Incentive Units vested and were converted to limited partner interests. In May 2005, ETE exchanged 631,320 ETP Common Units held by ETE and $1,046 in cash for the redemption of 4,858,300 limited partner interests in ETE, which were then retired. The redemption was determined to be no more than the fair value of the respective interests in ETE.
Other Incentive Interests
ETE’s partnership agreement provides for 72,874,494 Incentive Units (the ETE Incentive Units), consisting of: 24,291,498 “Tier I Units;” 12,145,749 “Tier II Units;” 12,145,749 “Tier III Units;” and 24,291,498 “Tier IV Units;” to be granted to ETC Holdings, LP, one of ETE’s limited partners, if certain “Tier” payouts are achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 24,291,498 ETE Incentive Units vested and were converted to limited partner interests. Subsequent to August 31, 2004, the “Tier” payout conditions as defined in the Partnership Agreement were achieved and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership.
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(Dollars in thousands)
ETP Restricted Unit Plan
Effective March 15, 2005 ETP declared a two-for-one split of its Common Units. The units discussed in the Restricted Unit Plan and the Long-Term Incentive Plan are reflected on a post-split basis.
ETP GP previously adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan (the Restricted Unit Plan), for certain directors and key employees of ETP GP and its affiliates. The Restricted Unit Plan provided rights to acquire up to 146,000 Common Units of ETP. The Restricted Unit Plan provided for the award or grant to key employees of the right to acquire Common Units of ETP on such terms and conditions (including vesting conditions, forfeiture or lapse of rights) as the Compensation Committee of ETP GP (the Compensation Committee) shall determine. In addition, eligible directors automatically received a director’s grant of 500 Common Units on each September 1, and newly elected directors were also entitled to receive a grant of 2,000 Common Units upon election or appointment to ETP’s Board. Directors of ETP who were ETP employees or employees of ETP GP were not entitled to receive a director’s grant of Common Units of ETP but could receive ETP Common Units as employees.
Generally, awards granted under the Restricted Unit Plan vested upon the occurrence of specified performance objectives established by the Compensation Committee at the time designations of grants were made, or if later, the three-year anniversary of the grant date. In the event of a “change of control” (as defined in the Restricted Unit Plan), all rights to acquire ETP Common Units pursuant to the Restricted Unit Plan immediately vested. Pursuant to the January 2004 acquisition of ETP GP by ETE, the change of control provisions of the Restricted Unit Plan were triggered, resulting in the early vesting of 21,600 units by Heritage. Individuals holding 4,500 grants waived their rights to early vesting under the change of control provisions.
The issuance of ETP Common Units pursuant to the Restricted Unit Plan was intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of ETP’s Common Units. Therefore, no consideration was payable by the plan participants upon vesting and issuance of ETP’s Common Units. Following the June 23, 2004 approval of the 2004 Unit Plan at the special meeting of ETP Unitholders, the Restricted Unit Plan was terminated (except for the obligation to issue Common Units at the time the 16,592 units previously awarded vest), and no additional grants will be made under the Restricted Unit Plan.
Deferred compensation expense of $42 was recognized under the Restricted Unit Plan for the year ended August 31, 2004.
ETP follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 Accounting for Stock-based Compensation (SFAS 123). SFAS 123 requires that significant assumptions be used during the year to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. ETP assumed a weighted average risk free interest rate of 2.35% for the year ended August 31, 2004, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. Annual average cash distributions at the grant date were estimated to be $2.22 for the year ended August 31, 2004. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant.
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ETP Long Term Incentive Plan
Effective September 1, 2000, ETP GP adopted a long-term incentive compensation plan whereby ETP Common Units were to be awarded to the Executive Officers of ETP GP upon achieving certain targeted levels of Distributed Cash (as defined in the Long Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years Distributed Cash per unit. A minimum of 500,000 units on a post-split basis and if targeted levels were achieved, a maximum of 1,000,000 units were available for award under the Long Term Incentive Plan. In connection with the acquisition by ETE of ETP GP in January 2004, 300,036 units vested and Common Units were issued, and the Long-Term Incentive Plan terminated.
ETP 2004 Unit Plan
On June 23, 2004 at a special meeting of the Common Unitholders of ETP, ETP’s Common Unitholders approved the terms of ETP’s 2004 Unit Plan (the Plan), which provides for awards of ETP Common Units and other rights to ETP’s employees, officers, and directors. The maximum number of ETP Common Units that may be granted under this Plan is 900,000 total units issued. Any awards that are forfeited or which expire for any reason, or any units which are not used in the settlement of an award will be available for grant under the Plan. Units to be delivered upon the vesting of awards granted under the Plan may be (i) units acquired by ETP in the open market, (ii) units already owned by ETP or its General Partner, (iii) units acquired by ETP or its General Partner directly from ETP, or any other person, (iv) units that are registered under a registration statement for this Plan, (v) Restricted Units, or (vi) any combination of the foregoing.
Employee Grants. The Compensation Committee of ETP, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any Change in Control as defined by the Plan or upon such terms as the Compensation Committee may require at the time the award is granted. As of August 31, 2004, no grants of awards had been made to any employee under the 2004 Unit Plan. As of May 31, 2005, awards totaling 259,200 units were made under the 2004 Unit Plan to employees, including executive officers. These awards will vest subject to vesting over a three-year period based upon the achievement of certain performance criteria. Vested awards will convert into ETP Common Units upon the third anniversary of the measuring date for the grants, which is September 1 of each year. Vesting occurs based upon the total return to ETP’s Unitholders as compared to a group of Master Limited Partnership peer companies. The issuance of ETP Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units.
Director Grants. Each director of ETP GP who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (Director Participant), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 4,000 ETP Common Units (the Initial Director’s Grant). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of ETP Common Units equal to $15,000 divided by the fair market value of an ETP Common Units on such date (Annual Director’s Grant). Each grant of an award to a Director Participant will vest at the rate of 20% per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director
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Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. As of May 31, 2005, initial Director’s Grants totaling 16,844 Units have been made.
Long-Term Incentive Grants. The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of August 31, 2004, there has been no Long-Term Incentive Grants made under the Plan.
This Plan will be administered by the Compensation Committee of the Board of Directors of ETP LLC and may be amended from time to time by the Board; provided however, that no amendment will be made without the approval of a majority of the Unitholders (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the Plan; (iii) materially increase the cost of the Plan to the Partnership; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later that the 10th anniversary of its original effective date.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, deferred taxes, and general business and medical self-insurance reserves. Actual results could differ from those estimates.
Accounting for Derivative Instruments and Hedging Activities
The Company applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Company has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception, the Company formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Company also
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assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Company determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The Company utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Company designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. As of August 31, 2004, these hedging instruments had a net fair value of $85, which was recorded as price risk management assets and liabilities on the balance sheet through other comprehensive income net of minority interest.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.
Recently Issued Accounting Standards
In January of 2003, the Financial Accounting Standards Board (“FASB”) issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51 (FIN 46). In December 2003, the FASB issued FIN 46R, which clarified certain issues identified in FIN 46. FIN 46R requires an entity to consolidate a variable interest entity if the entity is designated as the primary beneficiary of that variable interest entity even if the entity does not have a majority of voting interest. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception of any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this interpretation must be applied at the beginning of the first interim or annual period beginning after March 15, 2004. The implementation of FIN 46 did not have an impact on the Company’s consolidated financial position.
As of August 31, 2004, the Company owned various unconsolidated entities in which its share of the unconsolidated entities ranges from 49% to 50%. The Company accounts for its investments under the equity method of accounting as prescribed by APB Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. The Company does not control these entities, and each partner shares in all profits and losses equal to their respective share in the entities. There are no limits on the exposure to losses or on the ability to share in returns. Based on the analysis performed, the Company is not the primary beneficiary of the entities, and as a result, will not consolidate the entities but will continue to account for the investment in these entities under the equity method.
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(Dollars in thousands)
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity (SFAS 150). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS 150 as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company adopted the provisions of SFAS 150 as of September 1, 2003. The adoption did not have a material impact on the Company’s consolidated financial position
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require the Company to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Company’s consolidated financial position.
SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The Company does not expect SFAS 123R to have a material impact on its consolidated financial position.
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on the Company’s consolidated financial position.
SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s consolidated financial position.
EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been
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disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The Company accounted for the sale of ETP’s discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.
3. ACQUISITIONS:
On June 2, 2004, ETC OLP acquired the transportation assets of TXU Fuel Company (formerly the TUFCO System now referred to as the ET Fuel System) for $498,571 in cash. The assets include approximately 2,000 miles of intrastate pipeline and related storage facilities located in Texas, with a total system capacity of 1.3 billion cubic feet or natural gas per day. The purchase price was funded with borrowings under ETC OLP’s amended debt agreement.
These assets allow ETC OLP to provide multiple services to producers in four major producing areas of Texas, as well as providing access to major natural gas markets. In addition, these assets are expected to provide significant growth opportunities for the Company going forward. The acquisition was accounted for using the purchase method. The purchase price was initially allocated based on the estimated fair values of the individual assets acquired and the liabilities assumed at the date of the acquisition. The final allocation of the purchase price was completed in the third quarter of fiscal year 2005 upon the completion of an independent appraisal.
During the period from January 20, 2004 to August 31, 2004, HOLP acquired substantially all of the assets of three propane companies, which included Edwards Propane of Marshville, North Carolina, Custer Gas Service of Custer, South Dakota, and one other small company. The aggregate purchase price for these acquisitions totaled $16,967, which included liabilities assumed of $268. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. These acquisitions were financed primarily with the HOLP Senior Revolving Acquisition facility and were accounted for by the purchase method under SFAS 141.
Acquisitions subsequent to August 31, 2004
In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Gas Services for $64,632 in cash, which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $66,667 which included $64,632 of cash paid and liabilities assumed of $2,035. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets were integrated into ETP’s Southeast Texas System and are expected to provide increased throughput capacity to ETP’s existing midstream assets. The acquisition was not material for pro forma disclosure purposes.
In January 2005, ETP acquired the controlling interests in Houston Pipeline System and related storage facilities (“HPL”) from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350,000 of ETP Common Units. In addition, ETP acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing from ETE which was re-paid in full prior to May 31, 2005. The total purchase price of $1,410,189 which included $1,039,358 of cash paid, net of cash acquired and liabilities assumed of $413,270, including $800 in estimated acquisition costs, was allocated to the assets
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(Dollars in thousands)
acquired and liabilities assumed. Under the terms of the transaction, ETP, through ETC OLP, its wholly-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables ETP to expand its current transportation systems into areas where it previously did not have a presence, and in combination with ETP’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor.
During the nine months ended May 31, 2005, HOLP acquired substantially all of the assets of seven propane businesses. The aggregate purchase price for these acquisitions totaled $18,109 which included $13,875 of cash paid, net of cash acquired, 120,550 Common Units on a post-split basis valued at $2,500 when issued and liabilities assumed of $1,734. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for these acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.
Assets acquired and purchase price allocation
The assets acquired and purchase price allocation of material acquisitions for the year ended August 31, 2004 were as follows:
| ET Fuel System June 2, 2004 |
HOLP acquisitions (aggregated) January 20, 2004 to August 31, 2004 |
|||||||
| Accounts receivable |
$ | — | $ | 1,612 | ||||
| Inventory |
— | 335 | ||||||
| Other current assets |
57 | — | ||||||
| Investment in unconsolidated affiliate |
— | — | ||||||
| Property, plant and equipment |
499,789 | 8,024 | ||||||
| Intangibles |
1,560 | |||||||
| Goodwill |
10,327 | 5,437 | ||||||
| Total assets acquired |
510,173 | 16,968 | ||||||
| Accounts payable |
— | — | ||||||
| Accrued expenses |
(758 | ) | (52 | ) | ||||
| Other current liabilities |
— | (1 | ) | |||||
| Deposits from vendor |
(750 | ) | — | |||||
| Exchanges payable |
(10,094 | ) | — | |||||
| Long-term debt |
— | (215 | ) | |||||
| Minority interests |
— | — | ||||||
| Total liabilities assumed |
(11,602 | ) | (268 | ) | ||||
| Net assets acquired |
$ | 498,571 | $ | 16,700 | ||||
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AUGUST 31, 2004
(Dollars in thousands)
The assets acquired and purchase price allocation of acquisitions subsequent to August 31, 2004 were as follows:
| Texas Chalk and Madison Systems November 2004 |
HPL January 2005 |
HOLP acquisitions (aggregated) September 1, 2004 to May 31, 2005 |
||||||||||
| Cash and equivalents |
$ | — | $ | 191 | $ | 5 | ||||||
| Accounts receivable |
— | 370,378 | 429 | |||||||||
| Inventory |
— | 130,280 | 243 | |||||||||
| Other current assets |
— | 23,567 | 184 | |||||||||
| Investment in unconsolidated affiliate |
— | 32,940 | — | |||||||||
| Price risk management assets |
— | 28,638 | — | |||||||||
| Property, plant and equipment |
66,667 | 824,386 | 11,074 | |||||||||
| Intangibles |
— | 3,740 | ||||||||||
| Goodwill |
— | — | 2,439 | |||||||||
| Total assets acquired |
66,667 | 1,410,380 | 18,114 | |||||||||
| Accounts payable |
(525 | ) | (313,469 | ) | (233 | ) | ||||||
| Accrued expenses |
(1,510 | ) | (36,077 | ) | (352 | ) | ||||||
| Other current liabilities |
— | (13,247 | ) | |||||||||
| Other liabilities |
— | (6,710 | ) | |||||||||
| Deposits from vendor |
— | — | ||||||||||
| Price risk management liabilities |
— | (28,638 | ) | |||||||||
| Exchanges payable |
— | — | ||||||||||
| Long-term debt |
— | (1,149 | ) | |||||||||
| Minority interests |
— | (15,129 | ) | — | ||||||||
| Total liabilities assumed |
(2,035 | ) | (413,270 | ) | (1,734 | ) | ||||||
| Net assets acquired |
$ | 64,632 | $ | 997,110 | $ | 16,380 | ||||||
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4. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:
Long-term debt of ETP and its operating subsidiaries consists of the following on a consolidated basis:
| Year Ended August 31, 2004 |
||||
| HOLP Notes |
||||
| 1996 8.55% Senior Secured Notes |
$ | 84,000 | ||
| 1997 Medium Term Note Program: |
||||
| 7.17% Series A Senior Secured Notes |
12,000 | |||
| 7.26% Series B Senior Secured Notes |
18,000 | |||
| 6.50% Series C Senior Secured Notes |
1,786 | |||
| 2000 and 2001 Senior Secured Promissory Notes: |
||||
| 8.47% Series A Senior Secured Notes |
9,600 | |||
| 8.55% Series B Senior Secured Notes |
27,429 | |||
| 8.59% Series C Senior Secured Notes |
27,000 | |||
| 8.67% Series D Senior Secured Notes |
58,000 | |||
| 8.75% Series E Senior Secured Notes |
7,000 | |||
| 8.87% Series F Senior Secured Notes |
40,000 | |||
| 7.21% Series G Senior Secured Notes |
15,200 | |||
| 7.89% Series H Senior Secured Notes |
8,000 | |||
| 7.99% Series I Senior Secured Notes |
16,000 | |||
| ETC OLP Term Loan Facility |
725,000 | |||
| HOLP Senior Revolving Acquisition Facility |
23,000 | |||
| HOLP Long term portion of the Senior Revolving Working Capital Facility |
10,000 | |||
| HOLP Notes payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010 |
18,218 | |||
| HOLP Other |
2,160 | |||
| Current maturities of long-term debt |
(31,235 | ) | ||
| $ | 1,071,158 | |||
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(Dollars in thousands)
Maturities of HOLP’s Senior Secured Notes, the Medium Term Note Program and the Senior Secured Promissory Notes (the HOLP Notes) are as follows:
| 1996 8.55% Senior Secured Notes: | ||
| mature at the rate of $12,000 on June 30 in each of the years 2002 to and including 2011. Interest is paid semi-annually. | ||
| 1997 Medium Term Note Program: | ||
| Series A Notes: |
mature at the rate of $2,400 on November 19 in each of the years 2005 to and including 2009. Interest is paid semi-annually. | |
| Series B Notes: |
mature at the rate of $2,000 on November 19 in each of the years 2003 to and including 2012. Interest is paid semi-annually. | |
| Series C Notes: |
mature at the rate of $714 on March 13 in each of the years 2000 to and including 2003, $357 on March 13, 2004, $1,073 on March 13, 2005, and $357 in each of the years 2006 and 2007. Interest is paid semi-annually. | |
| 2000 and 2001 Senior Secured Promissory Notes: | ||
| Series A Notes: |
mature at the rate of $3,200 on August 15 in each of the years 2003 to and including 2007. Interest is paid quarterly. | |
| Series B Notes: |
mature at the rate of $4,571 on August 15 in each of the years 2004 to and including 2010. Interest is paid quarterly. | |
| Series C Notes: |
mature at the rate of $5,750 on August 15 in each of the years 2006 to and including 2007, $4,000 on August 15, 2008 and $5,750 on August 15, 2009 to and including 2010. Interest is paid quarterly. | |
| Series D Notes: |
mature at the rate of $12,450 on August 15 in each of the years 2008 and 2009, $7,700 on August 15, 2010, $12,450 on August 15, 2011 and $12,950 on August 15, 2012. Interest is paid quarterly. | |
| Series E Notes: |
mature at the rate of $1,000 on August 15 in each of the years 2009 to and including 2015. Interest is paid quarterly. | |
| Series F Notes: |
mature at the rate of $3,636 on August 15 in each of the years 2010 to and including 2020. Interest is paid quarterly. | |
| Series G Notes: |
mature at the rate of $3,800 on May 15 in each of the years 2004 to and including 2008. Interest is paid quarterly. | |
| Series H Notes: |
mature at the rate of $727 on May 15 in each of the years 2006 to and including 2016. Interest is paid quarterly. | |
| Series I Notes: |
mature in one payment of $16,000 on May 15, 2013. Interest is paid quarterly. | |
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All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure HOLP’s Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, HOLP is required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of August 31, 2004 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that HOLP pay the additional 1% interest.
Effective August 31, 2004, ETC OLP entered into the Third Amendment to the Second Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $725,000 Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 4.45% as of August 31, 2004. The ETC OLP Term Loan Facility was secured by substantially all of the ETC OLP’s assets. As of August 31, 2004, the Term Loan Facility had a balance of $725,000. In January 2005 the balance of the ETC OLP Term Loan Facility was paid in full.
A $225,000 Revolving Credit Facility was available through January 18, 2008. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The maximum commitment fee payable on the unused portion of the ETC OLP facility was 0.50%. The facility was fully secured by substantially all of ETC OLP’s assets. As of August 31, 2004, there were no amounts outstanding under the ETC OLP Revolving Credit Facility, and $4,650 in letters of credit outstanding which reduce the amount available for borrowing under the ETC OLP Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40,000.
Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $75,000 HOLP Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the HOLP Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.2038% for the amount outstanding at August 31, 2004. The maximum commitment fee payable on the unused portion of the HOLP facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Working Capital Facility. As of August 31, 2004, the HOLP Senior Revolving Working Capital Facility had a balance outstanding of $24,550, of which $10,000 was long-term and $14,550 was short-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Working Capital Facility. Letter of Credit Exposure plus the HOLP Working Capital Loan cannot exceed the $75,000 maximum HOLP Working Capital Facility. HOLP had outstanding Letters of Credit of $1,002 at August 31, 2004.
A $75,000 HOLP Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the HOLP Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.2038% for the amount outstanding at August 31, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Acquisition Facility. As of August 31, 2004, the HOLP Senior Revolving Acquisition Facility had a balance outstanding of $23,000.
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The agreements for each of the HOLP Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and HOLP and ETC OLP’s (collectively the Operating Partnerships) bank credit facilities contain customary restrictive covenants applicable to the Operating Partnerships, including limitations on substantial disposition of assets, changes in ownership of the Operating Partnerships, the level of additional indebtedness and creation of liens. These covenants require the Operating Partnerships to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the Operating Partnership’s bank credit facilities and the HOLP Note Agreements) of not more than, 4.75 to 1.0 for HOLP and 4.75 to 1.0 during the 365-day period following the funding of the purchase price of the ET Fuel System and to 4.0 to 1.0 during any period other than the 365-day period following the funding of the purchase price of the ET Fuel System for ETC OLP and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1.0 for HOLP and 2.75 to 1 for ETC OLP. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the operating partnership’s bank credit facilities and the HOLP Note Agreements, Consolidated EBITDA is based upon the Operating Partnerships’ EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
Failure to comply with the various restrictive and affirmative covenants of the Operating Partnerships’ bank credit facilities and the HOLP Note Agreements could negatively impact the Operating Partnerships’ ability to incur additional debt and/or ETP’s ability to pay distributions. The Operating Partnerships are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the HOLP Senior Secured Notes, HOLP Medium Term Note Program, HOLP Senior Secured Promissory Notes, and the Operating Partnership’s bank credit facilities as of August 31, 2004.
Future maturities of long-term debt for each of the next five fiscal years and thereafter are $31,235 in 2005; $39,355 in 2006; $72,009 in 2007; $770,756 in 2008; $42,909 in 2009, and $146,129 thereafter.
Debt transactions subsequent to August 31, 2004
On January 18, 2005, in a Rule 144A private placement offering, ETP issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. ETP recorded debt issuance costs of $6,413 and a discount of $2,265 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities described above. On July 29, 2005, ETP completed a registered exchange offer to
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exchange newly issued 5.95% Senior Notes due 2015 which have been registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old Notes). The sole purpose of the exchange offer was to fulfill the obligations of ETP under the registration rights agreement entered into in connection with the sale by ETP of the Old Notes. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes.
On July 29, 2005 ETP Completed an offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, whereby ETP issued $400,000 in aggregate principal amount of 5.65% Senior Unsecured Notes due 2012. ETP’s Senior Notes due 2012 are fully and unconditionally guaranteed by ETC OLP and its subsidiaries guaranteeing ETP’s 5.95% senior notes due 2015.
Also on January 18, 2005, ETP entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under ETP’s Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. Effective June 2, 2005, ETP increased the unsecured Revolving Credit Facility from $700,000 to $800,000. The maximum commitment fee payable on the unused portion of the facility is 0.30%. ETP’s Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 and a daily rate based on the London market.
ETC OLP and its designated subsidiaries act as the guarantor of the debt obligations for the ETP Senior Unsecured Notes issued on January 18, 2005 and the ETP Revolving Credit Facility. If ETP were to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. ETP’s Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured debt.
On January 26, 2005, the Partnership borrowed $200,000 under a Senior Secured Term Facility with Goldman Sachs Credit Partners L.P, secured by the Partnership’s investment in ETP. The interest rate was based on either a Eurodollar rate plus 1.25% per annum, or a prime rate plus 0.250% per annum. Of the proceeds, $174,624 was used to finance the acquisition of working inventory of natural gas from HPL. The remaining proceeds of approximately $25,000 were re-paid in February 2005. The loan was paid in full on April 14, 2005.
On June 16, 2005, ETE entered into a $600,000 Senior Secured Loan Agreement with Goldman Sachs Credit Partners L.P., as administrative agent, and a syndicate of financial institutions that matures on June 16, 2008. Loans in an amount of $600,000 were borrowed and loans repaid under the term loan agreement may not be re-borrowed. The loans are secured by the Partnership’s ETP Common Units and general partner interest in ETP. ETE’s Senior Secured Loan Agreement requires that, on the last day of the specified fiscal quarter, the ratio of its Consolidated Funded Debt (as defined in the term loan agreement) to ETE’s Consolidated EBITDA (as defined in the term loan agreement) for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. ETE’s term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of ETE’s Consolidated EBITDA (as defined in ETE’s term loan agreement) to its Consolidated Interest Expense (as defined in ETE’s term loan agreement) must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008.
5. DISCONTINUED OPERATIONS:
On April 14, 2005, ETC OLP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191,606, including certain adjustments as defined
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AUGUST 31, 2004
(Dollars in thousands)
in the purchase and sale agreement. The sale of the Elk City System has been accounted for as discontinued operations.
6. INCOME TAXES:
The components of the deferred tax liability were as follows:
| Year Ended August 31, 2004 | |||
| Property, plant and equipment |
$ | 215,491 | |
| Other |
1,235 | ||
| Total |
$ | 216,726 | |
7. MAJOR CUSTOMERS
As of August 31, 2004, ETP had receivables due from BP Energy Company that represented approximately 15.0% of the Company’s total net accounts receivable. However, management believes that ETP’s portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk.
8. COMMITMENTS AND CONTINGENCIES:
Commitments
Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2020. Fiscal year future minimum lease commitments for such leases are $4,794 in 2005; $3,048 in 2006; $2,104 in 2007; $1,647 in 2008; $1,216 in 2009 and $628 thereafter.
ETP has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery up to 20 million British thermal units per day (MMBtu/d). Long-term contracts total require delivery of up to 156 MMBtu/d. The long-term contracts run through July 2013.
In connection with the HPL acquisition in January 2005, ETP acquired a sales agreement whereby ETP is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 1.8 million MMBtu, 9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. ETP also assumed a contract with a service provider which obligates ETP to obtain certain compressor, measurement and other services through 2007 with monthly payments of approximately $1,700.
ETP has signed long-term agreements with several parties committing firm transportation volumes into a new pipeline system, which ETP was required to construct, and which is referred to as the Bossier Pipeline. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO Energy Inc. agreement runs nine years beginning when the Bossier Pipeline becomes operational. The Bossier Pipeline became operational in June 2004.
ETC OLP in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. The Company believes that such terms
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(Dollars in thousands)
are commercially reasonable and will not have a material adverse effect on the Company’s financial position or results of operations.
ETP has entered into several propane purchase and supply commitments with varying terms as to quantities and prices, which expire at various dates through March 2006.
Litigation
ETP’s midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, ETC OLP is not currently a party to any material legal proceedings. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.
Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or are named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. ETP maintains liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.
Of the pending or threatened matters in which the ETP or its subsidiaries are a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P., and they were dismissed from the litigation. On October 21, 2004, HOLP announced that it received a favorable jury verdict with respect to the SCANA litigation. The jury found in favor of HOLP on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. SCANA has appealed the jury’s decision, and currently, the parties are involved in the appeal of a number of post-trial motions. ETP cannot predict whether the final judgment will affirm the jury verdict without any modification. Because of the uncertainty of the final determination and the net amount of funds ETP could receive, the Company cannot predict whether it will receive any of the damages award ETP may receive. The Company is entitled to a portion of that award only to the extent that ETP distributes any of the award to its Common Unitholders. As a result, management cannot yet predict whether the Company will receive any of the damages awarded by this verdict.
At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (B of A) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for
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AUGUST 31, 2004
(Dollars in thousands)
any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
ETP or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Company. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, ETP accrues the related deductible. As of August 31, 2004, an accrual of $930 was recorded as accrued and other current liabilities on the Company’s consolidated balance sheet.
Environmental
ETP’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although ETP believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, ETP has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has ETP’s operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in the Company’s August 31, 2004 balance sheet. Based on information currently available to the Company, such projects are not expected to have a material adverse effect on the Company’s financial condition or results of operations.
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NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the EPA) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on the Company’s financial condition or results of operations.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Company’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Company believes that such costs will not have a material adverse effect on its financial position. As of August 31, 2004, an accrual of $473 was recorded in the Company’s balance sheet to cover any material environmental liabilities that were not covered by the environmental indemnifications.
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NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
9. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
ETP is exposed to market risks related to the volatility of natural gas and NGL prices. To reduce the impact of this price volatility, ETP primarily uses derivative commodity instruments (futures and swaps) to manage its exposures to fluctuations in margins. The fair value of all price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income until the settlement month. The amount on the balance sheet relating to price risk management assets liabilities in accumulated other comprehensive income will be reclassified into earnings over the next twelve months. When the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in the statement of operations. Unrealized gains or losses on price risk management assets and liabilities that do not meet the requirements for hedge accounting are recognized in the statement of operations. ETP’s price risk management assets and liabilities were as follows:
| August 31, 2004: |
Commodity |
Notional Volume |
Maturity |
Fair Value |
||||||
| MMBTU | ||||||||||
| Basis Swaps IFERC/Nymex |
Gas | 54,472,500 | 2004-2005 | $ | 1,451 | |||||
| Basis Swaps IFERC/Nymex |
Gas | 62,767,500 | 2004-2005 | 592 | ||||||
| $ | 2,043 | |||||||||
| Swing Swaps IFERC |
Gas | 119,495,000 | 2004-2005 | $ | 704 | |||||
| Swing Swaps IFERC |
Gas | 45,265,000 | 2004-2005 | (399 | ) | |||||
| Swing Swaps IFERC |
Gas | 76,720,000 | 2006-2008 | — | ||||||
| $ | 305 | |||||||||
| Futures Nymex |
Gas | 10,057,500 | 2004-2005 | $ | (1,311 | ) | ||||
| Futures Nymex |
Gas | 12,677,500 | 2004-2005 | 2,941 | ||||||
| 1,630 | ||||||||||
| Barrels |
||||||||||
| NGL Swaps |
Condensate, Propane, Ethane |
250,000 | 2004-2005 | $ | (86 | ) | ||||
Estimates related to the Company’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Company attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Company’s positions.
Interest Rate Risk
ETP was exposed to market risk for changes in interest rates related to its bank credit facilities of ETC OLP. An interest rate swap agreement was used to manage a portion of the exposure related to ETC OLP’s Term Loan Facility to changing interest rates by converting floating rate debt to fixed-rate debt. On October 9, 2002, ETC
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(Dollars in thousands)
OLP entered into an interest rate swap agreement to manage its exposure to changes in interest rates. The interest rate swap had a notional value of $75,000 and matures on October 9, 2005. Under the terms of the interest rate swap agreement, the ETP will pay a fixed rate of 2.76% and received three-month LIBOR with quarterly settlement commencing on January 9, 2003. The value of the interest rate swap was marked to market. The value of the interest rate swap at August 31, 2004 was a liability of $539 and was recorded as a component of price risk management liabilities on the Company’s consolidated balance sheet.
10. MEMBERS’ EQUITY
The LE GP, LLC membership agreement contains specific provisions for the allocation of net earnings and losses to the members for purposes of maintaining the partner capital accounts. The Board of the Company may distribute to the Members funds of the Company which the Board reasonably determines are not needed for the payment of existing or foreseeable company obligations and expenditures.
11. ETP’s QUARTERLY DISTRIBUTION OF AVAILABLE CASH
The partnership agreement of ETP requires that ETP will distribute all of its Available Cash to its Unitholders and its general partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s partnership agreement.
Distributions by ETP in an amount equal to 100% of Available Cash will generally be made 98% to the Common, Class D, and Class E Unitholders and 2% to its general partner, ETP GP, subject to the payment of incentive distributions to ETP GP to the extent that certain target levels of cash distributions are achieved.
ETP makes distributions of available cash from operating surplus for any quarter in the following manner:
| • | First, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to its general partner, until each Common Unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”); |
| • | Second, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to its general partner, until each Common Unit has received $0.275 per unit for such quarter (the “first target distribution”); |
| • | Third, 85% to all Common and Class E Unitholders, in accordance with their percentage interests, 13% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner, until each Common Unit has received at least $0.3175 per unit for such quarter (the “second target distribution”); |
| • | Fourth, 75% to all Common and Class E Unitholders, in accordance with their percentage interests, 23% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner, until each Common Unit has received at least $0.4125 per unit for such quarter; (the “third target distribution”); and |
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AUGUST 31, 2004
(Dollars in thousands)
| • | Fifth, thereafter, 50% to all Common and Class E Unitholders, in accordance with their percentage interests, 48% to the holders of Incentive Distribution Rights, pro rata, and 2% to its general partner. |
Notwithstanding the foregoing, any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E unit may not exceed $2.82 per year.
12. RELATED PARTY TRANSACTIONS:
Accounts payable to related companies as of August 31, 2004 includes approximately $1,400 payable to unconsolidated affiliates for purchases of natural gas.
ETP’s natural gas midstream operations secure compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the ETG Entities. ETP’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of ETP’s General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services.
One of ETP’s natural gas midstream subsidiaries owns a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by one of the General Partner’s directors. ETP is the operator of the Dorado System. At August 31, 2004, there was a balance of $248 owing to ETP by a director of ETP LLC for services ETP provided as operator. This balance was paid in full subsequent to August 31, 2004.
13. SUPPLEMENTAL INFORMATION:
Following is the balance sheet of the Company which is included to provide additional information with respect to the LE GP, LLC’s financial position on a stand-alone basis as of August 31, 2004:
| ASSETS |
|||
| CURRENT ASSETS: |
|||
| Cash and cash equivalents |
$ | 7 | |
| Total current assets |
7 | ||
| INVESTMENT IN ENERGY TRANSFER EQUITY, L.P. |
3,994 | ||
| Total assets |
$ | 4,001 | |
| LIABILITIES AND MEMBER’S EQUITY |
|||
| Member’s equity |
4,001 | ||
| Total liabilities and member’s equity |
$ | 4,001 | |
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NOTES TO CONSOLIDATED BALANCE SHEET—(Continued)
AUGUST 31, 2004
(Dollars in thousands)
14. SUBSEQUENT EVENTS:
On January 27, 2005, ETP announced that the Board of Directors of its general partner approved a two-for-one split for each class of ETP’s limited partner units. The split entitled Unitholders of record at the close of business on February 28, 2005 to receive one additional Partnership unit for each Partnership unit owned on that date. The distribution was made on March 15, 2005. The effect of the split was to double the number of all outstanding Common Units and to reduce by half the minimum quarterly per unit distribution and the targeted distribution levels. All periods presented and all references to Common Units of ETP have been restated to reflect the effects of the unit split.
In June 2005, ETP completed the sale of 1,640,000 common units to a group of executive managers of ETP, including the President, Vice President and General Counsel, and Vice President-Corporate Development. The units were sold at a price of $31.95 per common unit, which represented a 6% discount to the closing common unit price on June 17, 2005. The transaction was approved by a committee of independent directors of ETP. From the proceeds of approximately $52,000, $30,000 was used to pay outstanding indebtedness on ETP’s revolving credit facility and the remainder was used by ETP for general company purposes.
On July 26, 2005, ETP completed the sale of 3,000,000 common units in a private sale to an institutional investor. The common units were issued pursuant to ETP’s effective shelf registration statement and the proceeds of $105,600 were used by ETP to retire a portion of the outstanding indebtedness on its revolving credit facility and to fund ETP’s recently announced capital expansion projects.
ETP also entered into a long-term agreement in July 2005 with XTO Energy Inc. to transport minimum annual volumes over a ten-year term on pipelines to be constructed by ETP. XTO will also be entitled to transport additional volumes under similar terms. The newly constructed pipelines will consist of 264 miles of 30 inch, 36 inch and 42 inch pipelines while adding approximately 40,000 horsepower of compression. The estimated cost of the pipeline construction project is estimated to be approximately $454,000.
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CONDENSED CONSOLIDATED BALANCE SHEET
(in thousands)
(unaudited)
| May 31, 2005 | |||
| ASSETS |
|||
| CURRENT ASSETS: |
|||
| Cash and cash equivalents |
$ | 21,614 | |
| Marketable securities |
2,658 | ||
| Accounts receivable, net of allowance for doubtful accounts |
729,261 | ||
| Accounts receivable from related companies |
653 | ||
| Inventories |
261,413 | ||
| Deposits paid to vendors |
46,441 | ||
| Exchanges receivable |
19,819 | ||
| Price risk management asset |
36,307 | ||
| Prepaid expenses and other |
59,774 | ||
| Total current assets |
1,177,940 | ||
| PROPERTY, PLANT AND EQUIPMENT, net |
2,824,372 | ||
| LONG-TERM PRICE RISK MANAGEMENT ASSETS |
18,824 | ||
| INVESTMENT IN AFFILIATES |
40,857 | ||
| GOODWILL |
351,320 | ||
| INTANGIBLES AND OTHER ASSETS, net |
109,037 | ||
| Total assets |
$ | 4,522,350 | |
| LIABILITIES AND MEMBER’S EQUITY |
|||
| CURRENT LIABILITIES: |
|||
| Accounts payable |
773,904 | ||
| Accounts payable to related companies |
3,572 | ||
| Exchanges payable |
20,612 | ||
| Customer deposits |
24,978 | ||
| Accrued and other current liabilities |
119,316 | ||
| Price risk management liabilities |
38,736 | ||
| Income taxes payable |
1,075 | ||
| Current maturities of long-term debt |
33,425 | ||
| Total current liabilities |
1,015,618 | ||
| LONG-TERM DEBT, less current maturities |
1,570,155 | ||
| LONG-TERM PRICE RISK MANAGEMENT LIABILITIES |
18,860 | ||
| OTHER NON-CURRENT LIABILITIES |
16,660 | ||
| DEFERRED TAXES |
219,224 | ||
| MINORITY INTERESTS |
1,677,539 | ||
| 4,518,056 | |||
| COMMITMENTS AND CONTINGENCIES |
|||
| MEMBER’S EQUITY: |
4,294 | ||
| Total liabilities and member’s equity |
$ | 4,522,350 | |
The accompanying notes are an integral part of this unaudited consolidated balance sheet.
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May 31, 2005
(Dollars in thousands)
(unaudited)
1. OPERATIONS AND ORGANIZATION:
LE GP, LLC (the Company) is the general partner of Energy Transfer Equity LP (“ETE”). LE GP, LLC is a Texas limited liability company controlled by common ownership of ETC Holdings, LP (“Holdings”). On August 23, 2005, the Company converted from a Texas limited liability company to a Delaware limited liability company. LE GP, LLC and the general partner of Holdings are ultimately owned and controlled by the Co-CEOs of ETP, and Natural Gas Partners, a venture capital investor. The Company owns a 0.01% general partner interest in ETE which entitles it to receive all of the cash distributions made by ETE related to this general partner interest. These distributions are the Company’s primary source of cash flow.
As of May 31, 2005, ETE owned all of the equity interests in Energy Transfer Partners GP, LP (“ETP GP”), which entitled ETE to receive all of the cash distributions made by ETP GP related to its general partner interest and the related incentive distribution rights.
In September 2004, the Partnership sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, the Partnership sold a 5% limited partner interest in ETE to this group. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were contributed together with the 4.6662% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interests together were deemed to be an equivalent value of the 5% limited partner interest in ETE. The equivalent value was determined to be the book value of the Common Units and the interests in ETP GP and ETP LLC that were contributed.
The accompanying unaudited consolidated balance sheet and notes thereto of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, it does not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements.
In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated balance sheet of LE G.P., LLC and subsidiaries as of May 31, 2005 The unaudited interim consolidated financial statements should be read in conjunction with the consolidated balance sheet and notes thereto of Energy Transfer Partners presented elsewhere in this document for the fiscal year ended August 31, 2004.
Energy Transfer Transactions
On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (now known as Energy Transfer Equity, L.P. (“ETE”) completed the series of transactions whereby ETE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage in exchange for cash, Common Units, Class D Units and Special Units of Heritage. Simultaneously, ETE acquired the General Partner of Heritage, ETP GP and ETP LLC from their owners, and coupled with the Heritage Limited Partner interests ETE received, thereby gained control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) from the owners of ETP GP.
Subsequent to the Energy Transfer Transactions, Heritage changed its name to Energy Transfer Partners, L.P., and began trading on the New York Stock Exchange under the ticker symbol “ETP”. The name change and new ticker symbol were effective March 1, 2004.
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May 31, 2005
(Dollars in thousands)
(unaudited)
Accounting Treatment of the Energy Transfer Transactions
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards 141, Business Combinations (“SFAS 141”). Although Heritage was the surviving parent entity for legal purposes, ETE was the acquirer for accounting purposes. Consequently, the Company’s financial statements do not reflect 100% of the results of Heritage, HHI, ETP GP, or ETP LLC within the period, as those results prior to January 19, 2004 (the date of the Energy Transfer Transactions) are not included. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The Partnership, in accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141 recorded a gain of approximately $395,000 as a result of the Energy Transfer Transactions. ETE accounted for the transaction as a partial sale of ETC OLP and a partial acquisition of Heritage, and recognized the gain to the extent ETC OLP was sold and stepped up the assets of ETC OLP to the extent ETC OLP was acquired by the minority shareholders. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by ETE through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%.
The acquisition of HHI by Heritage was accounted for as a capital transaction at ETP as the primary asset held by HHI was 8,853,832 Common Units of ETP on a post-split basis (see “Other Developments” below). Following the acquisition of HHI by ETP, the Heritage Common Units held by HHI were converted to Class E Units of ETP.
The issuance of the additional ETP Common Units upon the conversion of ETP Special Units adjusted the percent of Heritage acquired by ETE in the Energy Transfer Transactions and resulted in an additional fair value step-up being recorded on Heritage’s assets in accordance with EITF 90-13. Upon the conversion of the Special Units on June 23, 2004, ETE acquired approximately 41.5% of Heritage.
The excess purchase price over Heritage’s cost was determined as follows:
| Net book value of Heritage at January 20, 2004 |
$ | 239,102 | ||
| Historical goodwill at January 20, 2004 |
(170,500 | ) | ||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 267,210 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Equity interest acquired |
$ | 110,892 | ||
| Fair market value of Limited Partner Units |
668,534 | |||
| Purchase price of General Partner Interest |
30,000 | |||
| Equity investment from public offering |
355,948 | |||
| Treasury Class E Unit purchase |
(157,340 | ) | ||
| 897,142 | ||||
| Percent of Heritage acquired by Energy Transfer Equity |
41.5 | % | ||
| Fair value of equity acquired |
372,314 | |||
| Net book value of equity acquired |
110,892 | |||
| Excess purchase price over Heritage cost |
$ | 261,422 | ||
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
The excess purchase price over Heritage cost was allocated as follows:
| Property, plant and equipment (25 year life) |
$ | 35,269 | |
| Customer lists (15 year life) |
18,926 | ||
| Trademarks |
19,251 | ||
| Goodwill |
187,976 | ||
| $ | 261,422 | ||
Goodwill was warranted in the Energy Transfer Transactions because the business enterprise value of the operations acquired exceeded the fair market value of the tangible and identifiable intangible assets acquired. The allocation of the purchase price reflects the final assessment of asset values of Heritage acquired in the Energy Transfer Transactions.
The gain recognized by ETE as a result of the Energy Transfer Transaction was determined as follows:
| ETE’s historical basis in ETC OLP |
$ | (90,906 | ) | |
| Percent sold in Energy Transfer Transactions |
58.5 | % | ||
| (53,180 | ) | |||
| Fair value of Heritage equity acquired in Energy Transfer Transactions |
372,314 | |||
| Less: Consideration paid for ETP’s GP interest |
(30,000 | ) | ||
| Fair value of assets received in Energy Transfer Transactions |
342,314 | |||
| Gain on partial sale of ETC OLP |
$ | 395,494 | ||
The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE in the Energy Transfer Transactions of approximately 58.5%, determined in accordance with Emerging Issues Task Force EITF 90-13 and SFAS 141. The step up resulted in an approximate $504,000 increase to property, plant and equipment at ETE which is being depreciated over estimated lives 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributable to a taxable entity of ETC OLP, resulting in approximately $108.5 million of deferred taxes recorded by ETE. The deferred taxes will reverse at the same rate as the related step-up in assets will be depreciated.
Accounting Treatment of the General Partner Transaction
Goodwill of $29,589 was recorded in connection with ETE’s acquisition of ETP GP. Goodwill was warranted because, as the General Partner of ETP, ETP GP owns certain incentive distribution rights, which entitle it to receive distributions in excess of its 2% general partner interest in ETP.
Business Operations
Subsequent to the Energy Transfer Transactions described above, LE GP LLC conducts business operations only through the two wholly owned operating partnerships of ETP, ETC OLP and HOLP (collectively the Operating Partnerships).
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
ETC OLP is engaged in midstream natural gas and transportation operations. ETC OLP owns and operates natural gas gathering, natural gas intrastate pipeline systems, and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and Louisiana. ETC OLP is a Texas limited partnership formed in October 2002 and is 99.9% owned by ETE and 0.1% owned by ETC OLP’s general partner LA GP, LLC, a wholly-owned subsidiary of ETP. ETC OLP is the 99.9% limited partner to ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Oklahoma Pipeline Ltd, which was sold on April 14, 2005, ETC Katy Pipeline, Ltd., ETC Processing, Ltd. and ETC Marketing, Ltd. and the 99% limited partner to ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. ETC OLP also owns a 50% interest in Vantex Gas Pipeline Company, LLC, a 50.5% interest in Vantex Energy Services, Ltd., and a 49% interest in Ranger Pipeline, L.P. These investments are accounted for under the equity method of accounting as ETC OLP exercises significant influence over these entities but lacks controlling interests. On June 29, 2005, ETP bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd. ETC OLP was contributed to Heritage on January 19, 2004, and thus became a wholly-owned subsidiary of ETP.
As of May 31, 2005, ETC OLP owns an interest in and operates approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to its gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities. The midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. The transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, the East Texas Pipeline, the natural gas pipeline and storage assets that are referred to as the ET Fuel System, and the natural gas pipeline and storage assets of the recently acquired HPL System.
The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Pipeline. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas.
ETC OLP also includes the recently acquired HPL System which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. The HPL System consists of six main transportation pipelines and three market area loops and has direct access to multiple market hubs at Katy, the Houston Ship Channel, Ague Dulce and through its operations of the Bammel storage facility. ETP also recently announced the completion of the Fort Worth Basin Pipeline. The 55-mile, 24 inch natural gas pipeline connects to its existing pipelines in North Texas and provides transportation for natural gas production from the Barnett Shale producing area. The construction costs were financed entirely with cash from operations.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
HOLP, a Delaware limited partnership, is engaged in retail and wholesale propane operations. HOLP sells propane and propane-related products to more than 700,000 active residential, commercial, industrial, and agricultural customers in 34 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership, a Canadian partnership in which the Partnership owns a 60% interest, is engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP enters into forward purchases and sales agreements for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C.
Other Developments
On June 20, 2005, ETP completed the sale of 1,640,000 Common Units to a group of executive managers of ETP. The proceeds were approximately $52,000, of which $30,000 was used to pay outstanding debt of ETP and the remaining proceeds will be used for ETP’s general partnership purposes. ETE sold a 5% limited partner interest to this group in exchange for its contribution of 1,638,692 Common Units of ETP, its 4.9995% limited partner interest in ETP GP and 5% of the member interests of ETP LLC. The value of the contribution and the interests received in exchange for those contributions were equivalent and were recorded at the value of the Common Units and limited partner interests and member interests received.
New Accounting Standards
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require the Company to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Company’s consolidated financial position.
SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The Company does not expect SFAS 123R to have a material impact on its consolidated financial position.
SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on the Company’s consolidated financial position.
SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction—a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s consolidated financial position.
EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The Company accounted for the sale of ETP’s discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.
2. ACQUISITIONS:
In November 2004, ETP acquired the Texas Chalk and Madison Systems from Devon Gas Services for $64,632 in cash, which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $66,667 which included $64,632 of cash paid and liabilities assumed of $2,035. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets were integrated into ETP’s Southeast Texas System and are expected to provide increased throughput capacity to ETP’s existing midstream assets. The acquisition was not material for pro forma disclosure purposes.
In January 2005, ETP acquired the controlling interests in the Houston Pipeline System and related storage facilities (“HPL”) from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. This acquisition was financed by ETP through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350,000 of ETP Common Units. In addition, ETP acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing from ETE (see Note 15) which was re-paid in full prior to May 31, 2005. The total purchase price of $1,410,189 which included $1,039,358 of cash paid, net of cash acquired and liabilities assumed of $413,270, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Included in prepaid expenses and other on the consolidated balance sheet as of May 31, 2005 is $42,400 in receivables due from AEP related to the HPL acquisition. Under the terms of the transaction, ETP, through ETC OLP, its wholly-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables ETP to expand its current transportation systems into areas where it previously did not have a presence, and in combination with ETP’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in ETP’s transportation and storage operating segment.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
During the nine months ended May 31, 2005, HOLP acquired substantially all of the assets of seven propane businesses. The aggregate purchase price for these acquisitions totaled $18,109 which included $13,875 of cash paid, net of cash acquired, 120,550 Common Units on a post-split basis valued at $2,500 when issued and liabilities assumed of $1,734. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for these acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.
Each of these acquisitions was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, and each purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition.
The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on the fair values for these acquisitions (in thousands):
| Texas Chalk and Madison Systems November 2004 |
HPL January 2005 |
HOLP acquisitions (aggregated) |
||||||||||
| Cash and equivalents |
$ | — | $ | 191 | $ | 5 | ||||||
| Accounts receivable |
— | 370,378 | 429 | |||||||||
| Inventory |
— | 130,280 | 243 | |||||||||
| Other current assets |
— | 23,567 | 184 | |||||||||
| Investments in unconsolidated affiliate |
— | 32,940 | — | |||||||||
| Price risk management assets |
— | 28,638 | — | |||||||||
| Property, plant, and equipment |
66,667 | 824,386 | 11,074 | |||||||||
| Intangibles |
— | — | 3,740 | |||||||||
| Goodwill |
— | — | 2,439 | |||||||||
| Total assets acquired |
66,667 | 1,410,380 | 18,114 | |||||||||
| Accounts payable |
(525 | ) | (313,469 | ) | (233 | ) | ||||||
| Accrued expenses |
(1,510 | ) | (36,077 | ) | (352 | ) | ||||||
| Other current liabilities |
— | (13,247 | ) | — | ||||||||
| Other liabilities |
— | (6,710 | ) | — | ||||||||
| Price risk management liabilities |
— | (28,638 | ) | — | ||||||||
| Long-term debt |
— | — | (1,149 | ) | ||||||||
| Minority interest |
— | (15,129 | ) | — | ||||||||
| Total liabilities assumed |
(2,035 | ) | (413,270 | ) | (1,734 | ) | ||||||
| Net assets acquired |
$ | 64,632 | $ | 997,110 | $ | 16,380 | ||||||
The purchase prices have been allocated by ETP based on the fair values of the assets acquired and liabilities assumed at the date of acquisition. The preliminary allocation may be adjusted to reflect the final purchase price allocation which will be based on an independent appraisal, if applicable. In addition, ETP continues to evaluate the acquisition of HPL and further adjustments may be necessary following an independent appraisal of fair market values, completion of the working capital settlement, and other adjustments under the purchase and sale agreement.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
During the nine months ended May 31, 2005, ETP completed a verification of the working gas inventory contained in the storage facilities it had acquired in two acquisitions and has adjusted the preliminary allocations of the purchase prices to reflect the verified amounts. AEP has notified ETP that it intends to review the results of the verification pertaining to the HPL acquisition, and further adjustments may be necessary based on the final outcome of AEP’s review and any final determinations made in accordance with the purchase and sale agreement.
3. USE OF ESTIMATES:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, deferred taxes, fair values of unit based compensation Actual results could differ from those estimates.
4. ACCOUNTS RECEIVABLE:
ETC OLP’s midstream and transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). ETP’s management reviews midstream and transportation accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation operations.
ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due.
HOLP grants credit to its customers for the purchase of propane and propane-related products. Also included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane segments are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for HOLP is based on management’s assessment of the realizability of customer accounts. ETP’s management’s assessment is based on the overall creditworthiness of HOLP’s customers and any specific disputes.
Accounts receivable consisted of the following at May 31, 2005, excluding amounts from discontinued operations:
| Accounts receivable midstream and transportation |
$ | 665,966 | ||
| Accounts receivable propane |
67,277 | |||
| Less—allowance for doubtful accounts |
(3,982 | ) | ||
| Total, net |
$ | 729,261 | ||
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
5. INVENTORIES:
Inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following at May 31, 2005, excluding amounts related to discontinued operations:
| Natural gas, propane and other NGLs |
$ | 247,665 | |
| Appliances, parts and fittings and other |
13,748 | ||
| Total inventories |
$ | 261,413 | |
6. PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Company capitalizes certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.
The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, ETP reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the periods presented.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
Components and useful lives of property, plant and equipment were as follows at May 31, 2005:
| Land and improvements |
$ | 37,882 | ||
| Buildings and improvements (10 to 30 years) |
57,797 | |||
| Pipelines and equipment (10 to 65 years) |
1,988,278 | |||
| Natural gas storage (40 years) |
29,862 | |||
| Bulk storage, equipment and facilities (3 to 30 years) |
56,321 | |||
| Tanks and other equipment (5 to 30 years) |
353,591 | |||
| Vehicles (5 to 10 years) |
76,766 | |||
| Right of way (20 to 65 years) |
95,150 | |||
| Furniture and fixtures (3 to 10 years) |
10,249 | |||
| Linepack |
23,896 | |||
| Pad gas |
102,557 | |||
| Other (5 to 10 years) |
21,147 | |||
| 2,853,496 | ||||
| Less—Accumulated depreciation |
(130,896 | ) | ||
| 2,722,600 | ||||
| Plus—Construction work-in-process |
101,772 | |||
| Property, plant and equipment, net |
$ | 2,824,372 | ||
7. DEPOSITS:
Deposits are paid to vendors in ETP’s midstream and transportation and storage business as prepayments for natural gas deliveries in the following month. ETC OLP makes prepayments when the volume of business with a vendor exceeds ETC OLP’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $3,747 as of May 31, 2005. ETP uses a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage its exposure to market fluctuations in the prices of natural gas and NGLs. ETP enters into these financial instruments with brokers who are clearing members with the NYMEX and directly with counterparties in the over-the-counter (“OTC”) market and is subject to margin deposit requirements under the OTC agreements and NYMEX positions. The NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by the counterparties when the financial instrument settles. ETP also has maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative(s) exceed(s) ETP’s pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date. ETP also has deposits with derivative counterparties as of May 31, 2005 of $42,694.
Deposits are received from ETP’s midstream and transportation and storage customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane use. Prepayments and security deposits may also be required when ETP’s customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $24,978 as of May 31, 2005.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
8. EMPLOYEE INCENTIVE INTERESTS:
ETE’s partnership agreement as amended and restated provides for certain incentive interests for certain employees. The employee incentive interests consists of 12,145,749 Employee Incentive Units granted to certain employees on the formation of ETE (the “Employee Incentive Units”).
The Employee Incentive Units vest ratably over a three-year period from the date of grant or fully vest upon the occurrence of a Fundamental Change as defined in ETE’s partnership agreement. The Employee Incentive Units were limited partner interests in ETE (as defined in the amended and restated agreement of limited partnership of ETE) and afforded the recipients with certain rights as limited partners in accordance with their terms. Employees must forfeit all vested and unvested Employee Incentive Units when the employee voluntarily terminates his or her employment or is terminated with cause as defined in ETE’s partnership agreement. The Employee Incentive Units granted shall be forfeited upon the fifth anniversary of the grant if the required “Tier I Payout,” as defined in ETE’s partnership agreement, has not yet occurred.
The Partnership accounts for the Employee Incentive Interests in accordance with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123). Under SFAS 123, total compensation is measured at the fair value of the award on the grant date and compensation expense is recorded ratably over the service period. Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive prior to vesting of the Employee Incentive Interests.
As a result of The Energy Transfer Transactions in January 2004, all Employee Incentive Units vested and were converted to limited partner interests, and the “Tier I Payout” was met giving effective rights as a limited partner in ETE to the holders of the Employee Incentive Units who ceased to be employees of ETE and became employees of ETP and its subsidiaries. In May 2005, ETE exchanged 631,320 ETP Common Units held by ETE and $1,046 in cash for the redemption of 4,858,300 limited partner interests in ETE, which were then retired. The redemption was determined to be no more than the fair value of the respective interests in ETE.
9. ETE INCENTIVE INTERESTS:
ETE’s partnership agreement provides for 72,874,494 Incentive Units (the ETE Incentive Units), consisting of: 24,291,498 “Tier I Units;” 12,145,749 “Tier II Units;” 12,145,749 “Tier III Units;” and 24,291,498 “Tier IV Units” to be granted to ETC Holdings, LP, one of ETE’s limited partners, if certain “Tier” payouts are achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 24,291,498 ETE Incentive Units held by ETC Holdings vested and were converted to limited partner interests in the Partnership and the “Tier 1” payout was met giving ETC Holdings effective rights in additional limited partner interests in the Partnership. Subsequent to May 31, 2005, the remaining “Tier” payout conditions as defined in the Partnership Agreement were achieved and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership.
10. UNIT BASED COMPENSATION PLANS:
The Company follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-based Compensation (SFAS 123) for ETE’s Employee Incentive Interests and ETP’s unit based compensation plans. SFAS 123 requires that significant assumptions be used during the period
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. ETP assumed a weighted average risk-free interest rate of 2.83% for the nine months ended May 31, 2005, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. The average fair value of the awards granted during the nine months ended May 31, 2005 was $34.00. Annual average cash distributions at the grant date were estimated to be $1.63 on a post-split basis for the nine months ended May 31, 2005. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant.
Management determined the estimated fair value of the Employee Incentive Units on the grant date was insignificant due primarily to the preferred distributions the other partners would receive until vesting of the Employee Incentive Interests. As a result of the Energy Transfer Transaction in January 2004, all Employee Incentive Units vested and were converted to limited partner interests and the “Tier I Payout” was met giving effective rights as a limited partner in ETE to the holders of the Employee Incentive Units who ceased to be employees of ETE and became employees of ETP and its subsidiaries.
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LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
11. WORKING CAPITAL FACILITY AND LONG-TERM DEBT
Long-term debt of ETP and its operating subsidiaries consists of the following on a consolidated basis as of May 31, 2005
| 1996 8.55% Senior Secured Notes |
$ | 84,000 | ||
| 1997 Medium Term Note Program: |
||||
| 7.17% Series A Senior Secured Notes |
12,000 | |||
| 7.26% Series B Senior Secured Notes |
16,000 | |||
| 6.50% Series C Senior Secured Notes |
714 | |||
| 2000 and 2001 Senior Secured Promissory Notes: |
||||
| 8.47% Series A Senior Secured Notes |
9,600 | |||
| 8.55% Series B Senior Secured Notes |
27,429 | |||
| 8.59% Series C Senior Secured Notes |
27,000 | |||
| 8.67% Series D Senior Secured Notes |
58,000 | |||
| 8.75% Series E Senior Secured Notes |
7,000 | |||
| 8.87% Series F Senior Secured Notes |
40,000 | |||
| 7.21% Series G Senior Secured Notes |
11,400 | |||
| 7.89% Series H Senior Secured Notes |
8,000 | |||
| 7.99% Series I Senior Secured Notes |
16,000 | |||
| 2005 5.95% Senior Notes, net of discount of $2,203 |
747,797 | |||
| ETC OLP Term Loan Facility |
— | |||
| HOLP Senior Revolving Acquisition Facility |
41,000 | |||
| ETP Revolving Credit Facility |
443,000 | |||
| ETP Swingline Loans |
30,000 | |||
| HOLP Long term portion of the Senior Revolving Working Capital Facility |
6,493 | |||
| HOLP Notes Payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010 |
16,370 | |||
| Other |
1,777 | |||
| Current maturities of long-term debt |
(33,425 | ) | ||
| $ | 1,570,155 | |||
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure HOLP’s Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, HOLP is required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status. As of May 31, 2005 the HOLP Notes were rated investment grade thereby alleviating the requirement that HOLP pay the additional 1% interest.
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
On January 18, 2005, in a Rule 144A and Regulation S under the Securities Act of 1933 private placement offering, ETP issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. ETP recorded debt issue costs of $6,413 and a discount of $2,265 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. As a result of the repayment, ETP wrote off $7,996 in deferred financing costs and accounted for the write-off as loss on extinguishment of debt in the consolidated statements of operations for the nine months ended May 31, 2005.
ETC OLP and its designated subsidiaries act as the guarantor of the debt obligations for the ETP Senior Unsecured Notes issued on January 18, 2005 and ETP Revolving Credit Facility. If ETP were to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. ETP’s Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured debt.
On July 29, 2005, ETP completed a registered exchange offer to exchange newly issued 5.95% Senior Notes due 2015 which were not registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old Notes). The sole purpose of the exchange offer was to fulfill the obligations of ETP under the registration rights agreement entered into in connection with the sale by ETP of the Old Notes. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes. On July 29, 2005 ETP completed an offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, whereby ETP issued $400,000 in aggregate principal amount of 5.65% Senior Unsecured Notes due 2012. The net proceeds of approximately $397,000 were used to repay a portion of the outstanding indebtedness on ETP’s Revolving Credit Facility. ETP’s Senior Notes due 2012 are fully and unconditionally guaranteed by ETC OLP and its subsidiaries guaranteeing ETP’s 5.95% senior notes due 2015.
Also on January 18, 2005, ETP entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under ETP’s Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. ETP borrowed $475,000 under its Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of May 31, 2005, $443,000 was outstanding under its Revolving Credit Facility. There was also $850 in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing. ETP’s Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 at a daily rate based on the London market. As of May 31, 2005, $30,000 was outstanding under the Swingline loan option. Total amount available under ETP’s Credit Agreement as of May 31, 2005 was $256,150. Effective June 2, 2005, ETP increased its unsecured Revolving Credit facility from $700,000 to $800,000.
Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:
A $75,000 HOLP Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.000% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the HOLP facility is 0.50%. HOLP must reduce the
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the HOLP Senior Revolving Working Capital Facility. Letter of Credit exposure plus the HOLP Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility. As of May 31, 2005, HOLP’s Senior Revolving Working Capital Facility had a balance outstanding of $6,493, which was long-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of its Working Capital Facility. HOLP completed the 30-day clean down requirement under its Senior Revolving Working Capital Facility on June 14, 2005 and had outstanding Letters of Credit of $1,002 at May 31, 2005.
A $75,000 Senior Revolving Acquisition Facility is available to HOLP through December 31, 2006. Amounts borrowed under the HOLP Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.715% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure its Senior Revolving Acquisition Facility. As of May 31, 2005, the HOLP Senior Revolving Acquisition Facility had a balance outstanding of $41,000.
The agreements for each of HOLP’s Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and HOLP’s bank credit facilities contain customary restrictive covenants applicable to the Operating Partnerships, including limitations on substantial disposition of assets, changes in ownership of the Operating Partnerships, the level of additional indebtedness and creation of liens. These covenants require HOLP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than, 4.50 to 1.0. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon HOLP EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that HOLP may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) HOLP’s restricted payment is not greater than the product of it’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
In addition, the Indenture relating to ETP’s Senior Notes issued on January 18, 2005 and its Revolving Credit Facility contain various covenants related to ETP’s ability to incur certain indebtedness, grant certain liens, enter into certain merger, sale or consolidation transactions, enter into sale-lease back transactions, and make certain investments. ETP’s Revolving Credit Facility also requires ETP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as similarly defined in ETP’s Revolving Credit Agreement) of not more than 4.50 to 1.00 at any time other than during a Specified Acquisition Period (as similarly defined in
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May 31, 2005
(Dollars in thousands)
(unaudited)
ETP’s Revolving Credit Agreement) and 5.00 to 1.00 during a Specified Acquisition Period. The ratio of Consolidated EBITDA for each period of four consecutive fiscal quarters, to Consolidated Interest Expense (as similarly defined in ETP’s Revolving Credit Agreement), will never be less than 3.00 to 1.00.
Failure to comply with the various restrictive and affirmative covenants of the discussed credit facilities and agreements could negatively impact the Partnership’s ability to incur additional debt and/or the Partnership’s ability to pay distributions. ETP and HOLP are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to ETP’s and HOLP’s debt agreements as of May 31, 2005.
On January 26, 2005, ETE borrowed $200,000 under a Senior Secured Term Facility with Goldman Sachs Credit Partners L.P., secured by the Partnership’s investment in ETP. The interest rate was based on either a Eurodollar rate plus 1.25% per annum, or a prime rate plus 0.250% per annum. Of the proceeds, $174,624 was used to finance the acquisition of working inventory of natural gas from HPL (see Note 3). The remaining proceeds of approximately $25,000 were re-paid in February 2005. The loan was paid in full April 14, 2005.
On June 16, 2005, ETE entered into a $600,000 Senior Secured Loan Agreement with Goldman Sachs Credit Partners L.P., as administrative agent, and a syndicate of financial institutions that matures on June 16, 2008. Loans in an amount of $600,000 were borrowed and loans repaid under the term loan agreement may not be re-borrowed. The loans are secured by the Partnership’s ETP Common Units and general partner interest in ETP. The Partnership’s Senior Secured Loan Agreement requires that, on the last day of the specified fiscal quarter, the ratio of its Consolidated Funded Debt (as defined in the term loan agreement) to the Partnership’s Consolidated EBITDA (as defined in the term loan agreement) for the fiscal quarter most recently ended, multiplied by four, be no greater than 6.25 to 1.0 for the fiscal quarter ending August 31, 2005 and declining over time to no greater than 4.0 to 1.0 for the fiscal quarter ending May 31, 2008. The Partnership’s term loan agreement also requires that, on the last day of the specified fiscal quarter, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Partnership’s term loan agreement) to its Consolidated Interest Expense (as defined in the Partnership’s term loan agreement) must not be less than 2.25 to 1.0 for the fiscal quarter ending August 31, 2005 and increasing over time to not less than 3.0 to 1.0 for the fiscal quarter ending May 31, 2008.
Also on January 18, 2005, ETP entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under ETP’s Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. ETP borrowed $475,000 under its Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of May 31, 2005, $443,000 was outstanding under its Revolving Credit Facility. There was also $850 in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing. ETP’s Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 at a daily rate based on the London market. As of May 31, 2005, $30,000 was outstanding under the Swingline loan option. Total amount available under ETP’s Credit Agreement as of May 31, 2005 was $256,150. Effective June 2, 2005, ETP increased its unsecured Revolving Credit Facility from $700,000 to $800,000.
Future maturities of long-term debt for the remainder of the current fiscal year, each of the next five fiscal years and thereafter are $21,021 remaining in 2005; $39,478 in 2006; $86,657 in 2007; $45,923 in 2008; $43,059 in 2009; $513,564 in 2010; and $847,344 thereafter.
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
Based on the estimated borrowing rates currently available to the Partnership for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at May 31, 2005 was $1,619,071 and $1,597,046, respectively.
Debt transactions subsequent to May 31, 2005
On July 29, 2005 ETP completed an offering pursuant to Rule 144A and Regulation S under the Securities Act of 1933, whereby ETP issued $400,000 in aggregate principal amount of 5.65% Senior unsecured notes due 2012. The net proceeds of approximately $397,000 were used to repay a portion of the outstanding indebtedness on ETP’s Revolving Credit Facility. ETP’s Senior Notes due 2012 are fully and unconditionally guaranteed by ETC OLP and its subsidiaries guaranteeing ETP’s 5.95% Senior Notes due 2015.
On July 29, 2005, ETP also completed a registered exchange offer to exchange newly issued 5.95% Senior Notes due 2015 which have been registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old Notes). The sole purpose of the exchange offer is to fulfill the obligations of ETP under the registration rights agreement entered into in connection with the sale by ETP of the Old Notes. The New Notes issued pursuant to the exchange offer will have substantially identical terms to the Old Notes.
12. INVESTMENT IN UNCONSOLIDATED AFFILIATES:
ETP owns interests in a number of related businesses that are accounted for using the equity method. In general, ETP uses the equity method of accounting for an investment in which there is a 20% to 50% ownership of its outstanding ownership interests and exercises significant influence over its operating and financial policies.
As a result of the HPL acquisition, ETP acquired a 50% ownership interest in Mid Texas Pipeline Company (MidTexas) which owns a 129-mile transportation pipeline system that connects various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. The investment is accounted for using the equity method of accounting. ETP does not exercise management control over MidTexas, and therefore, ETP is precluded from consolidating the MidTexas financial statements with those of its own.
The equity in earnings of unconsolidated affiliates, individually or in the aggregate, was not significant for the periods presented.
13. COMMITMENTS AND CONTINGENCIES:
ETP has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 415 MMBtu/d. Long-term contracts require delivery of up to 515 MMBtu/d. The long-term contracts run through October 2012.
In connection with the acquisition of the ET Fuel System in June of 2004, ETP entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. ETP also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005,
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
ETP was entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. TXU Shipper has notified ETP that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.
ETP has signed long-term agreements with several parties committing firm transportation volumes into the East Texas Pipeline which is part of the East Texas Pipeline System. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational, and expires in June 2012.
In connection with the HPL acquisition in January 2005, ETP acquired a sales agreement whereby ETP is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 1.8 million MMBtu, 9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. ETP also assumed a contract with a service provider which obligates ETP to obtain certain compressor, measurement and other services through 2007.
ETP in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. ETP believes that such terms are commercially reasonable and will not have a material adverse effect on ETP’s financial position or results of operations.
ETP has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices. The contracts expire at various dates through March 2006.
Litigation
ETP’s midstream operating partnership, ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.
Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or are named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. ETP maintains liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.
Of the pending or threatened matters in which ETP or its subsidiaries is a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the SCANA litigation). Prior to trial, a settlement was reached with defendant, Cornerstone Ventures, L.P., and they were dismissed from the litigation. The trial began on October 4, 2004 against the remaining defendants and testimony was concluded on October 20, 2004. On October 21, 2004, the jury returned a verdict in favor of HOLP against SCANA and in favor of defendant Suburban. The jury found in favor of HOLP on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. SCANA has appealed the jury’s decision, and currently the parties are involved in the appeal of a number of post-trail motions. ETP cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. Because of the uncertainty of the final determination and the net amount of funds ETP could receive, the Partnership cannot predict whether it will receive any of the damages award ETP may receive. The Partnership is entitled to a portion of that award only to the extent that ETP distributes any of the award to its Common Unitholders. As a result, management cannot yet predict whether ETP will receive any of the damages awarded by this verdict.
At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (B of A) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.
ETP or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against ETP. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of ETP. Once ETP’s management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, ETP accrues the related deductible. As of May 31, 2005 an accrual of $956 was recorded as accrued and other current liabilities on the consolidated balance sheet.
Environmental
ETP’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although ETP believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in
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May 31, 2005
(Dollars in thousands)
(unaudited)
substantial costs and liabilities. Accordingly, ETP has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has ETP’s operations contributed to the environmental issues at these sites. Based on information currently available to ETP, such projects are not expected to have a material adverse effect on ETP’s financial condition or results of operations.
In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the EPA) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by Heritage was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). Based upon information currently available to ETP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on ETP’s financial condition or results of operations.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position. As of May 31, 2005 an accrual of $2,020 was recorded in ETP’s balance sheet to cover any material environmental liabilities that were not covered by the environmental indemnifications. A receivable of $413 was recorded in ETE’s balance sheet as of May 31, 2005 to account for Aquila’s share of certain environmental liabilities.
14. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:
Commodity Price Risk
The Company applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as amended. This statement requires that all derivatives be
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May 31, 2005
(Dollars in thousands)
(unaudited)
recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The Company has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At the inception of a hedge, ETP formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. ETE also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.
The Company utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. Of the amount on the balance sheet relating to price risk management assets and liabilities in accumulated other comprehensive income, approximately $24,000 is expected to be reclassified into earnings over the next twelve months.
In the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contract. Such contracts are exempt from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. In connection with the HPL acquisition, ETP acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them.
The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.
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NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
The following table details the outstanding derivatives as of May 31, 2005:
| Commodity |
Notional Volume MMBTU |
Maturity |
Fair Value |
||||||||
| Basis Swaps IFERC/Nymex |
Gas | 117,304,500 | 2005 | $ | 3,167 | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 55,406,013 | 2006 | (4,198 | ) | ||||||
| Basis Swaps IFERC/Nymex |
Gas | 1,800,000 | 2007 | (277 | ) | ||||||
| $ | (1,308 | ) | |||||||||
| Basis Swaps IFERC/Nymex |
Gas | 160,806,194 | 2005 | $ | (6,739 | ) | |||||
| Basis Swaps IFERC/Nymex |
Gas | 102,855,860 | 2006 | 5,530 | |||||||
| Basis Swaps IFERC/Nymex |
Gas | 15,290,500 | 2007 | 479 | |||||||
| $ | (730 | ) | |||||||||
| Swing Swaps IFERC |
Gas | 148,265,000 | 2005 | $ | 935 | ||||||
| Swing Swaps IFERC |
Gas | 65,150,000 | 2006 | (53 | ) | ||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2007 | — | |||||||
| Swing Swaps IFERC |
Gas | 25,550,000 | 2008 | — | |||||||
| $ | 882 | ||||||||||
| Swing Swaps IFERC |
Gas | 158,495,000 | 2005 | $ | (41 | ) | |||||
| Swing Swaps IFERC |
Gas | 27,300,000 | 2006 | 133 | |||||||
| $ | 92 | ||||||||||
| Fixed Swaps |
Gas | 3,330,000 | 2005 | $ | 6,129 | ||||||
| Fixed Swaps |
Gas | 3,270,000 | 2006 | 8,919 | |||||||
| $ | 15,048 | ||||||||||
| Futures Nymex |
Gas | 37,652,500 | 2005 | $ | (9,338 | ) | |||||
| Futures Nymex |
Gas | 962,500 | 2006 | 9 | |||||||
| Futures Nymex |
Gas | 240,000 | 2007 | 224 | |||||||
| $ | (9,105 | ) | |||||||||
| Futures Nymex |
Gas | (72,001,000 | ) | 2005 | $ | 14,295 | |||||
| Futures Nymex |
Gas | (8,007,500 | ) | 2006 | (520 | ) | |||||
| $ | 13,775 | ||||||||||
| Options |
Gas | 5,210,000 | 2005 | $ | 6,946 | ||||||
| Options |
Gas | 10,000,000 | 2006 | 18,830 | |||||||
| Options |
Gas | 3,570,000 | 2007 | 8,032 | |||||||
| $ | 33,808 | ||||||||||
| Options |
Gas | (4,978,000 | ) | 2005 | $ | (19 | ) | ||||
| Options |
Gas | (10,730,000 | ) | 2006 | (166 | ) | |||||
| Options |
Gas | (4,300,000 | ) | 2007 | (281 | ) | |||||
| Options |
Gas | (732,000 | ) | 2008 | (406 | ) | |||||
| $ | (872 | ) | |||||||||
| Forward Contracts |
Gas | (5,210,000 | ) | 2005 | $ | (6,946 | ) | ||||
| Forward Contracts |
Gas | (10,000,000 | ) | 2006 | (18,830 | ) | |||||
| Forward Contracts |
Gas | (3,570,000 | ) | 2007 | (8,032 | ) | |||||
| $ | (33,808 | ) | |||||||||
| Forward Contracts |
Gas | 4,978,000 | 2005 | $ | 19 | ||||||
| Forward Contracts |
Gas | 10,730,000 | 2006 | 166 | |||||||
| Forward Contracts |
Gas | 4,300,000 | 2007 | 281 | |||||||
| Forward Contracts |
Gas | 732,000 | 2008 | 406 | |||||||
| $ | 872 | ||||||||||
| Barrels |
|||||||||||
| NGL Swaps |
Condensate | 15,000 | 2005 | $ | (179 | ) | |||||
F-177
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Index to Financial Statements
LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
Estimates related to the Company’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Company attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Company’s positions.
Interest Rate Risk
The Company is exposed to market risk for changes in interest rates related to its bank credit facilities and the bank credit facilities of ETP. ETP manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements, which allows ETP to effectively convert a portion of variable rate debt into fixed debt.
On January 6, 2005, ETP entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to the anticipated issuance of $750,000 in principal amount of fixed rate debt.
ETP also entered into various forward starting interest swaps from February 2005 through May 2005, in anticipation of the issuance of an additional bond offering in the third or fourth fiscal quarter of 2005. Due to certain market conditions, the bond offering was postponed until July 29, 2005. Such agreements were designated as cash flow hedges of an anticipated transaction under SFAS 133. When the forward starting interest swaps settle and the bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. Certain forward starting interest swaps settled during the nine months ended May 31, 2005 with a net $1,384 receipt from the counterparties. Forward starting interest swaps with a notional amount of $400,000 were outstanding as of May 31, 2005 and had a fair value of $4,233 which was recorded as a component of price risk management liabilities on the consolidated balance sheet.
ETP also has an interest rate swap with a notional amount of $75,000 that matures in October 2005. Under the terms of the swap agreement, ETP will pay a fixed rate of 2.76% and will receive three-month LIBOR with a quarterly settlement. The interest rate swap is not accounted for as a hedge but receives mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the consolidated statement of operations.
15. MEMBERS’ EQUITY:
The LE GP, LLC membership agreement contains specific provisions for the allocation of net earnings and losses to the members for purposes of maintaining the member’s equity accounts. The Board of the Company may cause the Company to distribute to the Members funds of the Company which the Board reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
F-178
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Index to Financial Statements
LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
16. RELATED PARTY TRANSACTIONS:
Accounts payable to related companies as of May 31, 2005 included approximately $2,387 payable to unconsolidated affiliates for purchases of natural gas and operating expenses incurred in the normal course of business.
In addition, ETC OLP is a party to various related party transactions. ETC OLP secures compression services from third parties. Energy Transfer Technologies, Ltd. Is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by ETP in conjunction with the January 2004 Energy Transfer Transactions. ETP’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of ETP’s General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. For the nine months ending May 31, 2005, payments totaling $898 were made to the ETG Entities for compression services provided to and utilized in ETC OLP’s operations.
ET GP, LLC, the general partner of Holdings has a general and administrative services contract to act as an advisor and provide certain general and administrative services to ETE and its affiliates. The general and administrative services that ET GP, LLC provides ETE under this contract include:
| • | General oversight and direction of engineering, accounting, legal and other professional and operational services required for the support, maintenance and operation of the assets used in the Midstream operations, and |
| • | The administration, maintenance and compliance with contractual and regulatory requirements. |
In exchange for these services, ETE is required to pay ET GP, LLC a $500 annual fee payable quarterly and pro-rated for any portion of a calendar year. Pursuant to this contract, ETE was also required to reimburse ET GP, LLC for expenses associated with formation of the Partnership and is required to indemnify ET GP, LLC, its affiliates, officers and employees for liabilities associated with the actions of ET GP, LLC, its affiliates, officers, and employees. The agreement expressly provides that the fee for the services cannot be paid from funds received by ETP, but only from the Partnership’s funds.
F-179
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Index to Financial Statements
LE GP, LLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED BALANCE SHEET—(Continued)
May 31, 2005
(Dollars in thousands)
(unaudited)
17. SUPPLEMENTAL INFORMATION:
Following is the balance sheet of the Company which is included to provide additional information with respect to LE GP, LLC’s financial position on a stand-alone basis as of May 31, 2005:
| ASSETS |
|||
| CURRENT ASSETS: |
|||
| Cash and cash equivalents |
$ | 7 | |
| Total current assets |
7 | ||
| INVESTMENT IN ENERGY TRANSFER EQUITY, LP |
4,298 | ||
| Total assets |
$ | 4,305 | |
| LIABILITIES AND MEMBER’S EQUITY |
|||
| Accounts payable to Related Parties |
$ | 11 | |
| Member’s equity |
4,294 | ||
| Total liabilities and member’s equity |
$ | 4,305 | |
18. SUBSEQUENT EVENTS:
On July 26, 2005, ETP completed the sale of 3,000,000 common units in a private sale to an institutional investor. The common units were issued pursuant to ETP’s effective shelf registration statement and the proceeds of $105.6 million were used by ETP to retire a portion of the outstanding indebtness on its revolving credit facility and to fund ETP’s recently announced capital expansion projects.
ETP also entered into a long-term agreement in July, 2005 with XTO Energy Inc. to transport minimum annual volumes over a ten-year term on pipelines to be constructed by the Partnership. XTO will also be entitled to transport additional volumes under similar terms. The newly constructed pipelines will consist of 264 miles of 30 inch, 36 inch and 42 inch pipelines while adding approximately 40,000 horsepower of compression. The estimated cost of the pipeline construction project is estimated to be approximately $454,000.
F-180
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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
La Grange Acquisition, LP and Affiliates
We have audited the accompanying consolidated balance sheets of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002, and the related consolidated statements of income, stockholder’s equity and cash flows for the period ended September 30, 2002 and the year ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002, and the results of their operations and their cash flows for the period ended September 30, 2002 and the year ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.
As discussed in the Note 1 to the consolidated financial statements, effective January 1, 2002, Aquila Gas Pipeline Corporation and Subsidiaries adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
July 17, 2003
F-181
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in thousands)
| September 30, 2002 |
||||
| Assets |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ | — | ||
| Accounts receivable |
72,154 | |||
| Materials and supplies |
2,622 | |||
| Price risk management assets |
18,100 | |||
| Other current assets |
66 | |||
| Receivable due from affiliated companies |
23,889 | |||
| Total current assets |
116,831 | |||
| Pipeline, property, plant and equipment, at cost: |
||||
| Natural gas pipelines |
465,441 | |||
| Plants and processing equipment |
93,872 | |||
| Other |
12,425 | |||
| 571,738 | ||||
| Less accumulated depreciation |
(210,399 | ) | ||
| 361,339 | ||||
| Intangible assets, net |
5,218 | |||
| Investment in Oasis Pipe Line |
100,748 | |||
| Other, net |
475 | |||
| Price risk management assets |
16,917 | |||
| Total assets |
$ | 601,528 | ||
| Liabilities and Stockholder’s Equity |
||||
| Current liabilities: |
||||
| Accounts payable |
$ | 71,981 | ||
| Accrued expenses |
3,938 | |||
| Accrued interest |
975 | |||
| Exchanges payable |
784 | |||
| Price risk management liabilities |
19,334 | |||
| Payable to affiliated companies |
47,064 | |||
| Total current liabilities |
144,076 | |||
| Long-term debt |
66,250 | |||
| Deferred income taxes |
121,718 | |||
| Price risk management liabilities |
15,225 | |||
| Commitments and contingencies |
— | |||
| Stockholder’s equity: |
||||
| Common stock, $1.00 par value, 1,000 shares authorized and 10 shares issued |
— | |||
| Additional paid-in capital |
90,591 | |||
| Retained earnings |
163,668 | |||
| Total stockholder’s equity |
254,259 | |||
| Total liabilities and stockholder’s equity |
$ | 601,528 | ||
See accompanying notes.
F-182
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
| Nine Months Ended September 30, 2002 |
Year Ended December 31, 2001 |
|||||||
| (In thousands) | ||||||||
| Operating revenues |
$ | 933,099 | $ | 1,813,850 | ||||
| Costs and expenses: |
||||||||
| Cost of sales |
880,064 | 1,715,261 | ||||||
| Operating |
12,717 | 18,126 | ||||||
| General and administrative |
9,575 | 19,949 | ||||||
| Depreciation and amortization |
22,915 | 30,779 | ||||||
| Unrealized loss (gain) on derivatives |
4,966 | (13,255 | ) | |||||
| Total costs and expenses |
930,237 | 1,770,860 | ||||||
| Income from operations |
2,862 | 42,990 | ||||||
| Other income (expense) |
(84 | ) | 1,901 | |||||
| Equity in net income of Oasis Pipe Line |
5,425 | 3,128 | ||||||
| Interest and debt expenses, net |
(3,931 | ) | (6,858 | ) | ||||
| Income before income taxes |
4,272 | 41,161 | ||||||
| Income tax (benefit) expense |
(467 | ) | 15,403 | |||||
| $ | 4,739 | 25,758 | ||||||
See accompanying notes.
F-183
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
Nine months ended September 30, 2002, and Year ended December 31, 2001
| Common Stock Shares |
Amount |
Additional Paid-in Capital |
Retained Earnings |
Total Stockholders Equity | ||||||||||
| (In thousands) | ||||||||||||||
| Balance, December 31, 2000 |
— | $ | — | $ | 90,591 | $ | 133,171 | $ | 223,762 | |||||
| Net income |
— | — | — | $ | 25,758 | 25,758 | ||||||||
| Balance, December 31, 2001 |
— | — | $ | 90,591 | 158,929 | 249,520 | ||||||||
| Net income |
— | — | — | 4,739 | 4,739 | |||||||||
| Balance, September 30, 2002 |
— | $ | — | $ | 90,591 | $ | 163,668 | $ | 254,259 | |||||
See accompanying notes.
F-184
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Nine Months Ended September 30, 2002 |
Year Ended December 31, 2001 |
|||||
| (In thousands) | ||||||
| Operating Activities |
||||||
| Net income |
4,739 | 25,758 | ||||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
||||||
| Depreciation and amortization, including interest |
22,935 | 30,827 | ||||
| Equity in (income) loss of Oasis Pipe Line |
(5,425 | ) | (3,128 | ) | ||
| Dividend from Oasis |
4,000 | 1,500 | ||||
| Deferred income taxes |
(956 | ) | 9,843 | |||
| Gain or loss on sale of assets |
61 | (3,838 | ) | |||
| Changes in operating assets and liabilities: |
||||||
| Accounts receivable |
48,939 | 102,688 | ||||
| Inventories and exchanges, net |
1,973 | 925 | ||||
| Net change in price risk management assets and liabilities |
7,168 | (7,056 | ) | |||
| Receivable due from affiliated companies |
(13,499 | ) | (10,390 | ) | ||
| Other assets |
455 | (171 | ) | |||
| Accounts payable |
(59,137 | ) | (98,802 | ) | ||
| Accrued expenses |
(4,531 | ) | (1,739 | ) | ||
| Accrued interest |
706 | (812 | ) | |||
| Payable to affiliated companies |
5,559 | 19,593 | ||||
| Net cash provided by operating activities |
12,987 | 65,198 | ||||
| Investing Activities |
||||||
| Additions to pipeline, property, plant and equipment |
(5,486 | ) | (26,866 | ) | ||
| Proceeds from asset dispositions |
4,999 | 6,139 | ||||
| Net cash used in investing activities |
(487 | ) | (20,727 | ) | ||
| Financing Activities |
||||||
| (Payments) borrowings under revolving credit agreement, net |
— | (31,971 | ) | |||
| Principal payments of debt |
(12,500 | ) | (12,500 | ) | ||
| Net cash used in investing activities |
(12,500 | ) | (44,471 | ) | ||
| Net (decrease) increase in cash and cash equivalents |
— | — | ||||
| Cash and cash equivalents, beginning of year |
— | — | ||||
| Cash and cash equivalents, end of year |
— | — | ||||
See accompanying notes.
F-185
Table of Contents
Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
1. Summary of Business, Basis of Presentation and Significant Accounting Policies
Business
Aquila Gas Pipeline Corporation (Aquila Gas Pipeline or the Company) and subsidiaries owned and operated natural gas gathering and pipeline systems and gas processing plants and was engaged in the business of purchasing, gathering, transporting, processing and marketing natural gas and natural gas liquids (NGLs) in the States of Texas and Oklahoma.
Effective October 1, 2002, substantially all of the operating assets of Aquila Gas Pipeline were sold for $264 million to La Grange Acquisition, LP (La Grange Acquisition). La Grange Acquisition did not assume Pipeline’s derivative positions or its liabilities, except for certain payables.
Principles of Consolidation and Basis of Presentation
Aquila Gas Pipeline was a wholly owned subsidiary of Aquila Merchant Services. Aquila Merchant Services was wholly owned by Aquila, Inc. (Aquila), formerly UtiliCorp United Inc.
The accompanying consolidated financial statements include the accounts of Aquila Gas Pipeline after the elimination of significant intercompany balances and transactions with subsidiaries. Unless otherwise indicated, all amounts included in the notes to the consolidated financial statements are expressed in thousands.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of estimates relate to the fair value of financial instruments and useful lives for depreciation. Actual results may differ from those estimates.
The Company was subject to a number of risks inherent in the industry in which it operated, primarily fluctuating prices and gas supply. The Company’s financial condition and results of operations depended significantly upon the prices received for natural gas and NGLs. These prices were subject to wide fluctuations due to a variety of factors that were beyond the control of the Company. In addition, the Company had to continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled depended on a variety of factors that were beyond the control of the Company.
Cash Paid for Interest
The following provides information related to cash paid for interest. No cash was paid for income taxes as taxes were settled through intercompany accounts with Aquila:
| September 30, 2002 |
December 31, 2001 | |||||
| (In thousands) | ||||||
| Interest, net of amount capitalized |
$ | 3,308 | $ | 6,219 | ||
F-186
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Revenue Recognition
Operating revenues were recognized upon the delivery of natural gas or NGLs to the buyer of the related product or services.
Inventories and Exchanges
Inventories and exchanges consisted of NGLs on hand or natural gas and NGLs delivery imbalances with others and were presented net by customer/supplier on the consolidated balance sheet. These amounts turned over monthly, and management believed that cost approximated market value. Accordingly, these volumes were valued at market prices on the consolidated balance sheet.
Materials and Supplies
Materials and supplies were stated at the lower of cost (determined on a first-in, first-out basis) or market.
Shipping and Handling Costs
In accordance with the Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs”, the Company classified all deductions from producer payments for fuel, compression and treating that can be considered handling costs as revenue. The associated fuel costs were included in cost of sales, while the remaining costs were included in operating costs.
Commodity Risk Management
In 1999, Aquila Gas Pipeline transferred all of its energy trading operations and management thereof to Aquila Energy Marketing (AEM), a wholly owned subsidiary of Aquila. AEM entered into forward physical contracts with third parties for the benefit of Aquila Gas Pipeline and where deemed necessary entered into intercompany financial derivative positions (e.g., swaps, futures and options) with Aquila Gas Pipeline and other affiliates to assist them in managing their exposures. Thus, Aquila Gas Pipeline had forward physical contracts with third parties and financial derivative positions with AEM and affiliates. The Company received all gross margins associated with these transactions, and AEM charged Aquila Gas Pipeline for its share of AEM’s costs to manage Aquila Gas Pipeline’s positions.
The Company accounted for its derivative positions, both speculative forward positions and financial derivatives, under Emerging Issues Task Force Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). Under EITF 98-10, the Company valued the derivative positions at market value with all changes being recognized in earnings. Realized gains and losses were included in revenues, while unrealized gains and losses were classified as such on the consolidated statements of income. Aquila Gas Pipeline’s derivative positions were classified as current or long-term price risk management assets and liabilities based on their maturity.
The market prices used to value these transactions reflected management’s estimates considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors of the underlying commitments. The values were adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under market conditions.
F-187
Table of Contents
Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Although La Grange Acquisition is also involved in energy marketing and uses derivatives to manage its exposures, La Grange Acquisition did not purchase Aquila Gas Pipeline’s derivative positions when it purchased its assets. Emerging Issues Task Force Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” was issued in the fourth quarter of 2002 and rescinded the provisions of EITF 98-10. As such all energy trading derivative transactions are now governed by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement No. 133). Under Statement No. 133, La Grange Acquisition will continue to account for its financial derivative positions as mark to market instruments. However, as permitted under Statement No. 133, La Grange Acquisition has adopted a policy of treating all forward physical contracts that require physical delivery as normal purchases and sales contracts. As such, these contracts will not be marked to market and will be accounted for when delivery occurs. Had Aquila Gas Pipeline adopted this policy, it would have reversed unrealized mark to market gains of $1,938 at September 30, 2002.
Pipeline, Property, Plant and Equipment
Pipeline, property, plant and equipment were stated at cost. Additions and improvements that added to the productive capacity or extended the useful life of the asset were capitalized. Expenditures for maintenance and repairs that did not add capacity or extended the useful life were charged to expense as incurred. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss was recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment were retired or sold, any gain or loss was included in operations.
Depreciation of the pipeline systems, gas plants and processing equipment was calculated using the straight-line method based on an estimated useful life of primarily 25 years. Interest cost on funds used to finance major pipeline projects during their construction period was also capitalized. Capitalized interest cost was $35 and $86 for the periods ending September 30, 2002 and December 31, 2001, respectively.
The Company reviewed its long-lived assets, including finite lived intangibles, for impairment whenever facts and circumstances indicated impairment was potentially present. When impairment indicators were present, Aquila Gas Pipeline evaluated whether the assets in question were able to generate sufficient cash flows to recover their carrying value on an undiscounted basis. If not, the Company impaired the assets to their fair value, which was determined based on discounted cash flows or estimated salvage value.
Construction work in progress at September 30, 2002 was $669.
Stock Compensation
Some of Aquila Gas Pipeline’s employees received stock options in Aquila. As permitted under generally accepted accounting principles, Aquila elected to account for the options under Accounting Principles Board Opinion No. 25, and because the options strike price was equal to or greater than the fair value at the date of grant, no compensation expense was recognized. See Note 6, for a summary of the options granted. As these were Aquila options, Aquila Gas Pipeline does not have full access to the information necessary to disclose what compensation expense would have been, had Aquila accounted for the options under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, which requires compensation expense be recognized for the fair value of the options at the date of grant. La Grange Acquisition does not have a stock option plan in place for its employees.
F-188
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Income Taxes
Aquila Gas Pipeline was included in the consolidated federal income tax returns filed by Aquila. Accordingly, all tax balances were ultimately settled through Aquila. Aquila Gas Pipeline had generally accounted for its taxes on a stand-alone or separate return basis (see Note 4). Periodically, taxes payable were settled through the intercompany accounts with Aquila and were not funded in cash.
The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (Statement No. 109). Statement No. 109 requires that deferred tax assets and liabilities be established for the basis differences between the reported amounts of assets and liabilities for financial reporting purposes and income tax purposes.
Equity Method Investments
Aquila Gas Pipeline had a 50% investment in Oasis Pipe Line Company. Aquila Gas Pipeline accounted for this investment using the equity method.
Adoption of New Accounting Standard
On January 1, 2002, Aquila Gas Pipeline adopted Statement of Financial Accounting Standards No. 141, “Business Combinations” (Statement No. 141). Statement No. 141 addresses financial accounting and reporting for business combinations and supersedes APB Opinion No. 16, “Business Combinations”, and FASB Statement 38, “Accounting for Preacquisition Contingencies of Purchased Enterprises.” Statement No. 141 was effective for all business combinations initiated after June 30, 2001. Statement No. 141 eliminated the pooling-of-interest method of accounting for business combinations. Statement No. 141 also changed the criteria to recognize intangible assets apart from goodwill. As the Company has historically used the purchase method to account for all business combinations, adoption of this statement did not have a material impact on the Aquila Gas Pipeline’s financial position or results of operations.
In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement No. 142). Statement No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and superseded APB Opinion No. 17, “Intangible Assets.” Statement No. 142 was effective for fiscal years beginning after December 15, 2001. This statement established new accounting for goodwill and other intangible assets recorded in business combinations. Under the new rules, goodwill and intangible assets deemed to have indefinite lives are no longer amortized but are be subjected to annual impairment tests in accordance with the statement. Other intangible assets continue to be amortized over their useful lives. Aquila Gas Pipeline adopted this standard on January 1, 2002. As amortization of goodwill was a significant non-cash expense, Statement No. 142 had a material impact on the Company’s financial statements. The table below summarizes the financial results as if adoption had occurred on January 1, 2001.
| 2001 |
||||
| (In thousands) | ||||
| Reported net income |
$ | 25,758 | ||
| Add back: Goodwill amortization |
900 | |||
| Add back: Oasis excess basis amortization |
1,650 | |||
| Taxes |
(365 | ) | ||
| Adjusted net income |
$ | 27,943 | ||
F-189
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
2. Related-Party Transactions
Aquila Gas Pipeline entered into various types of transactions with Aquila and its affiliates. Aquila Gas Pipeline sold natural gas to Aquila and its affiliates and purchased natural gas and NGLs from Aquila. Additionally, Pipeline reimbursed Aquila for the direct and indirect costs of certain Aquila employees who provided services to the Company and for other costs (primarily general and administrative expenses) related to the Company’s operations. Aquila also provided Aquila Gas Pipeline with a revolving credit agreement, as described in Note 3.
In addition, Aquila Gas Pipeline transported gas on Oasis Pipe Line Company’s (Oasis Pipe Line) pipeline. In 1999, Aquila Gas Pipeline had a 35 percent investment in the capital stock of Oasis Pipe Line, which was acquired in 1996 and was accounted for using the equity method of accounting. In December 2000, Pipeline’s investment in Oasis Pipe Line increased to 50 percent as a result of Oasis Pipe Line’s redemption of all the shares of one of its shareholders.
The following table summarizes transactions for the indicated periods:
| September 30, 2002 |
December 31, 2001 |
|||||||
| (In thousands) | ||||||||
| Natural gas sales to affiliated companies |
$ | 166,372 | $ | 325,295 | ||||
| NGLs sales to affiliated companies |
373 | 1,267 | ||||||
| Purchases of natural gas from affiliated companies |
101,398 | 170,105 | ||||||
| Purchases of NGLs from affiliated companies |
1,841 | — | ||||||
| Transportation expense with Oasis |
3,900 | 6,727 | ||||||
| Recognized (loss) gain from marketing transactions with AEM |
2,678 | (10,605 | ) | |||||
| Interest expense with Aquila |
3,295 | 5,140 | ||||||
| Reimbursement of direct costs to Aquila |
(1,739 | ) | 15,283 | |||||
| Service agreement expenses charged by Aquila |
2,628 | 3,504 | ||||||
The affiliated receivable due from Aquila was $23,889 for the period ending September 30, 2002. This receivable was created by overpayments on Aquila Gas Pipeline’s revolving credit agreement (see Note 3) with Aquila. The affiliated payable due to Aquila was $47,064 as of September 30, 2002.
3. Debt
The following table summarizes Aquila Gas Pipeline’s long-term debt:
| September 30, 2002 | ||
| (In thousands) | ||
| Loan agreement bearing interest at 6.83%, due 2006 |
16,250 | |
| Loan agreement bearing interest at 6.47%, due 2005 |
50,000 | |
| 8.29% senior notes, due 2002 |
— | |
| Total debt |
66,250 | |
| Less—Current maturities of long-term debt |
— | |
| Total long-term debt |
66,250 | |
F-190
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Revolving Credit Agreement
Aquila Gas Pipeline had a credit agreement, as amended, with Aquila that provided a revolving credit facility (Revolver) for borrowings of up to $115,000. As of September 30, 2002, there was $115,000 available for use under the Revolver. Aquila swept all available cash daily to reduce the revolver. This resulted in a receivable due to Aquila Gas Pipeline of $23,889 as of September 30, 2002. The Revolver bore interest at Aquila Gas Pipeline’s election of either (i) a base rate (the higher of the bank prime rate or 1/2 of 1 percent above the Federal Funds rate), (ii) an adjusted certificate of deposit rate or (iii) a Eurodollar rate. The maturity date of the Revolver automatically renewed in one-year periods from each commitment period (October of any given year), unless Aquila gave at least a one-year notice not to renew. As of September 30, 2002, the maturity date was October 2003. The Revolver was unsecured and was subordinate to the 8.29% senior notes described below. The Company paid an annual commitment fee to Aquila of 1/4 of 1% on the unutilized portion of the revolving credit facility. The Revolver required the Company to comply with certain restrictive covenants. At September 30, 2002, Aquila Gas Pipeline was in compliance with such covenants.
Loan Agreements
In 1995, Aquila Gas Pipeline entered into a loan agreement with Aquila Energy, a subsidiary of Aquila for $50,000. The loan was unsecured and bore interest at 6.47% due semi-annually. The principal amount of the loan was to be repaid to Aquila Energy by June 1, 2005. In 1997, Aquila Gas Pipeline entered into a second loan agreement with Aquila Energy for $16,250. This loan was unsecured and bore interest at 6.83% due semi-annually. The principal amount of the second loan was to be repaid to Aquila Energy by October 15, 2006.
Senior Notes
The 8.29% Senior Notes (Senior Notes) were unsecured and interest payments were due semi-annually. Principal payments of $12,500 were required each year and the balance was paid in full in September 2002. Upon issuance of the Senior Notes, Aquila Gas Pipeline deferred approximately $1,886 of initial fees and expenses that were amortized over the life of the notes.
4. Income Taxes
Components of income tax provision/(benefit) attributable to income before taxes are as follows:
| September 30, 2002 |
December 31, 2001 | ||||||
| (In thousands) | |||||||
| Current |
$ | 489 | $ | 5,560 | |||
| Deferred |
(956 | ) | 9,843 | ||||
| Total |
$ | (467 | ) | $ | 15,403 | ||
F-191
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Tax expense was different than the amount computed by applying the statutory federal income tax rate to income before taxes. A reconciliation of Aquila Gas Pipeline’s income taxes with the United States Federal statutory rate is as follows:
| September 30, 2002 |
December 31, 2001 |
|||||
| (In thousands) | ||||||
| Book income at U.S. federal statutory rate |
35.0 | % | 35.0 | % | ||
| Equity method earnings |
(51.4 | ) | (3.3 | ) | ||
| State taxes |
3.5 | 3.5 | ||||
| Other |
2.0 | 2.0 | ||||
| Tax provision effective rate |
(10.9 | )% | 37.2 | % | ||
Deferred taxes resulted from the effect of transactions that were recognized in different periods for financial and tax reporting purposes. Significant components of the Company’s deferred tax assets and liabilities were as follows:
| September 30, 2002 |
||||
| (In thousands) | ||||
| Deferred tax assets: |
||||
| Basis difference in intangible assets |
$ | 6,649 | ||
| Other |
388 | |||
| Total deferred tax assets |
7,037 | |||
| Deferred tax liabilities: |
||||
| Basis difference in fixed assets |
(128,755 | ) | ||
| Net deferred tax liabilities |
$ | (121,718 | ) | |
5. Major Customers
The Company’s gross sales as a percentage of total revenues to nonaffiliated major customers were as follows:
| September 30, 2002 |
December 31, 2001 |
|||||
| (In thousands) | ||||||
| Customer A |
17.5 | % | 15.4 | % | ||
| Customer B |
9.6 | % | 11.0 | % | ||
The Company’s natural gas operations had a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users, while its NGLs operations had a concentration of customers in the refining and petrochemical industries.
These concentrations of customers impacted the Company’s overall exposure to credit risk, whether positively or negatively, in that the customers were similarly affected by changes in economic or other conditions. However, management believed that Aquila Gas Pipeline’s portfolio of accounts receivable was sufficiently diversified to minimize any potential credit risk. Historically, Aquila Gas Pipeline has not incurred significant problems in collecting its accounts receivable and, as such, no allowance for doubtful accounts was provided in the accompanying consolidated financial statements. The Company’s accounts receivable were generally not collateralized.
F-192
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
6. Retirement and Benefit Plans
Aquila had a defined contribution plan for virtually all employees. Pursuant to the plan, employees of the Company could defer a portion of their compensation and contribute it to a deferred account. The Company’s matching contributions to the plan were $408 and $444 for the periods ended September 30, 2002 and December 31, 2001, respectively.
Aquila had a stock contribution plan under which eligible Aquila Gas Pipeline employees received a company contribution of 3 percent of their base income in Aquila common stock. The Company’s expense associated with this plan was $27 and $231 for periods ending September 30, 2002 and December 31, 2001, respectively. The reduction for 2002 was due to the reduction in the number of employees eligible in 2002 and declines in the market value of the stock.
Aquila had a stock option plan under which eligible Aquila Gas Pipeline employees were granted options to purchase shares of Aquila’s common stock. The plan provided that the options would not be granted at a price below the market price at the date of grant. Accordingly, no compensation cost was recognized for the options. The options vested one year from the date of grant and expired 10 years from the date of grant.
The following table summarizes the options granted to Aquila Gas Pipeline employees:
| Period Ended September 30, 2002 |
Period Ended December 31, 2001 | |||||||||
| Options |
Average Price |
Options |
Average Price | |||||||
| (In thousands) | ||||||||||
| Outstanding, beginning of period |
170,298 | 26.8387 | 115,876 | 21.9475 | ||||||
| Granted |
— | — | 85,810 | 34.8028 | ||||||
| Exercised |
(825 | ) | 18.2083 | (25,688 | ) | 23.4483 | ||||
| Forfeited |
(4,637 | ) | 22.7246 | (5,700 | ) | 21.6565 | ||||
| Outstanding, end of period |
164,836 | 26.6896 | 170,298 | 26.8387 | ||||||
7. Commitments and Contingencies
Lease Obligations
The Company had various non-cancelable operating leases. Total lease expense amounted to approximately $598 for the period ending September 30, 2002, and $1,059 for the period ending December 31, 2001. All leases were transferred to La Grange Acquisition effective October 1, 2002.
The following summarizes the future annual lease payments for the transferred leases for each of the next five years as of September 30, 2002:
| (In thousands) | |||
| 2003 |
$ | 775 | |
| 2004 |
775 | ||
| 2005 |
773 | ||
| 2006 |
64 | ||
| 2007 and thereafter |
— | ||
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
Taxes
The IRS has examined and proposed adjustments to Aquila’s consolidated federal income tax returns for 1988 through 1993. The proposed adjustment affecting the Company was to lengthen the depreciable life of certain pipeline assets owned by Aquila Gas Pipeline. Aquila has filed a petition in U.S. Tax Court contesting the IRS proposed adjustments for the years 1990 through 1991. The IRS has also proposed an adjustment on the same issue for 1992 through 1998. Aquila has tentatively agreed with the IRS to hold this issue in abeyance pending the outcome of the earlier petition.
Aquila intends to vigorously contest the proposed adjustment and believes it is reasonably possible that they will prevail. If resolved unfavorably, it is expected that additional assessments for the years 1999 through September 30, 2002 would be made on the same issue.
Any additional taxes would result in an adjustment to the deferred tax liability with no effect on net income, while any payment of interest or penalties would affect net income. Aquila Gas Pipeline expects that the ultimate resolution of this matter will not have a material adverse effect on its financial position. Under the Asset Purchase Agreement between Aquila and La Grange Acquisition, La Grange Acquisition would not be impacted by resolution of this matter.
Contingencies
In 1996, Aquila Gas Pipeline and Exxon entered into a contract, which required Aquila Gas Pipeline to pay Exxon $5.1 million in 2006 if Aquila Gas Pipeline failed to deliver natural gas containing at least 2 gallons per mcf to the Exxon Katy Plant. In 2000, the determination was made that it was unlikely that the Company would be in a position to supply natural gas that would meet the contract specifications. Included in operating expenses in 2000 was an accrual of $3.6 million representing the present value of the future settlement. In 2001, the Company reached an agreement with Exxon to cancel the contract for a cash settlement of $3.7 million and the exchange of property for right-of-way.
The Company was also a party to additional claims and was involved in various other litigation and administrative proceedings arising in the normal course of business. Aquila Gas Pipeline believed it was unlikely that the final outcome of any of the claims, litigation or proceedings to which it was a party would have a material adverse effect on its financial position or results of operations. However, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Company’s results of operations for the fiscal period in which such resolution occurred. Per the Asset Purchase Agreement between Aquila and La Grange Acquisition, Aquila has agreed to indemnify La Grange Acquisition for any litigation arising from operations before October 1, 2002.
In the normal course of business of its natural gas pipeline operations, the Company purchased, processed and sold natural gas pursuant to long-term contracts. Such contracts contained terms, which were customary in the industry. The Company believes that such terms were commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
F-194
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
8. Commodity Risk Management
The following table details information on the Company’s positions held or issued for trading purposes as of:
September 30, 2002
| Commodity |
Notional Volume Bcf |
Maturity |
Aquila Pays |
Aquila Receives |
Fair Value |
||||||||||
| Basis Swaps |
|||||||||||||||
| EPNG Permian |
Gas | 0.4 | 2002 | NYMEX | IFERC | $ | (142 | ) | |||||||
| EPNG Permian |
Gas | 0.4 | 2002 | IFERC | NYMEX | 143 | |||||||||
| Waha |
Gas | 3.3 | 2005 | NYMEX | IFERC | (711 | ) | ||||||||
| Waha |
Gas | 4.1 | 2005 | IFERC | NYMEX | 826 | |||||||||
| Houston Ship |
Gas | 0.6 | 2005 | NYMEX | IFERC | (40 | ) | ||||||||
| Houston Ship |
Gas | 0.6 | 2005 | IFERC | NYMEX | 44 | |||||||||
| EPNG Permian |
Gas | 1.5 | 2003 | NYMEX | IFERC | (723 | ) | ||||||||
| EPNG Permian |
Gas | 1.5 | 2003 | IFERC | NYMEX | 731 | |||||||||
| EPNG San Juan |
Gas | — | 2002 | NYMEX | IFERC | (456 | ) | ||||||||
| EPNG San Juan |
Gas | — | 2002 | IFERC | NYMEX | 714 | |||||||||
| Houston Ship |
Gas | 101.3 | 2005 | NYMEX | IFERC | (1,038 | ) | ||||||||
| Houston Ship |
Gas | 96.7 | 2005 | IFERC | NYMEX | 1,076 | |||||||||
| Katy |
Gas | — | 2002 | NYMEX | IFERC | (89 | ) | ||||||||
| Katy |
Gas | — | 2002 | IFERC | NYMEX | 94 | |||||||||
| TGP TX |
Gas | — | 2002 | NYMEX | IFERC | (36 | ) | ||||||||
| TGP TX |
Gas | — | 2002 | IFERC | NYMEX | 16 | |||||||||
| SOCAL |
Gas | 1.5 | 2003 | NYMEX | IFERC | (428 | ) | ||||||||
| SOCAL |
Gas | 1.5 | 2003 | IFERC | NYMEX | 174 | |||||||||
| TETC OLPO STX |
Gas | 13.6 | 2005 | NYMEX | IFERC | 274 | |||||||||
| TETC OLPO STX |
Gas | 11.7 | 2005 | IFERC | NYMEX | (130 | ) | ||||||||
| Waha |
Gas | 97.1 | 2003 | NYMEX | IFERC | (8,617 | ) | ||||||||
| Waha |
Gas | 97.1 | 2003 | IFERC | NYMEX | 8,531 | |||||||||
| Buyer/Seller |
Commodity |
Notional Volume Bcf |
Maturity |
Average Strike Price |
Fair Value |
||||||||||
| Futures |
Buyer | Gas | 0.3 | 2002 | 3.203 | $ | (121 | ) | |||||||
| Seller | Gas | 1.1 | 2002 | 2.685 | (1,086 | ) | |||||||||
| Buyer | Gas | 115.9 | 2005 | 3.733 | 29,518 | ||||||||||
| Seller | Gas | 114.3 | 2005 | 3.730 | (29,729 | ) | |||||||||
| Buyer | Gas | 2.5 | 2002 | 3.150 | 679 | ||||||||||
| Seller | Gas | 3.4 | 2002 | 2.995 | (810 | ) | |||||||||
| Forwards |
Buyer | Gas | 181.0 | 2020 | 2.919 | $ | (3,683 | ) | |||||||
| Seller | Gas | 339.7 | 2020 | 3.686 | 6,570 | ||||||||||
| Buyer | Transport | 15.3 | 2004 | 0.029 | (12 | ) | |||||||||
| Buyer/Seller |
Commodity |
Barrels in Thousands |
Maturity |
Average Strike Price |
Fair Value |
||||||||||
| NGLs Futures |
Seller | Ethane | 150 | 2002 | 0.215 | $ | 194 | ||||||||
| Buyer | Ethane | 150 | 2002 | 0.265 | 121 | ||||||||||
| Seller | Propane | 75 | 2002 | 0.373 | 265 | ||||||||||
| Buyer | Propane | 135 | 2002 | 0.406 | (287 | ) | |||||||||
| Seller | Crude | (254 | ) | 2002 | 29.552 | (1,374 | ) | ||||||||
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
The net gain from derivative activities for the periods ended September 30, 2002 and December 31, 2001 was $6,273 and $9,016, respectively.
9. Financial Instruments
The Company’s carrying amounts for cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated fair value. The fair values of its derivative positions are disclosed in Note 8. The following summarizes the Company’s carrying value and estimated fair value of its long-term debt obligations:
| September 30, 2002 | ||||||
| Carrying Value |
Fair Value | |||||
| (In thousands) | ||||||
| 6.83% Loan |
$ | 16,250 | $ | 19,123 | ||
| 6.47% Loan |
50,000 | 55,751 | ||||
| Total |
$ | 66,250 | $ | 74,874 | ||
10. Intangible Assets
The following table details the items included in intangible assets:
| Period Ended September 30, 2002 |
||||
| (In thousands) | ||||
| Goodwill |
$ | 9,491 | ||
| Less: amortization |
(7,837 | ) | ||
| 1,654 | ||||
| Oasis transportation rights |
18,620 | |||
| Less: amortization |
(15,905 | ) | ||
| 2,715 | ||||
| Gathering producer relationship |
14,930 | |||
| Less: amortization |
(14,081 | ) | ||
| 849 | ||||
| Intangibles, net |
$ | 5,218 | ||
Effective January 1, 2002, in accordance with Statements of Financial Accounting Standards No. 141 and No. 142, the Company ceased amortizing its goodwill. Further, the Company concluded that the carrying value of the goodwill was not impaired. Goodwill amortization was $900 in 2001. Amortization expense, excluding goodwill amortization, was $3,644 and $5,031 in September 30, 2002 and December 31, 2001, respectively.
F-196
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Index to Financial Statements
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Nine Months Ended September 30, 2002, and Year Ended December 31, 2001
(In thousands)
At September 30, 2002, the estimated five-year amortization of the Oasis Pipe Line transportation rights and gathering producer relationships was as follows:
| (In thousands) | |||
| Remainder of 2002 |
$ | 840 | |
| 2003 |
1,990 | ||
| 2004 |
91 | ||
| 2005 |
91 | ||
| 2006 |
91 | ||
| 2007 |
91 | ||
| Thereafter |
370 | ||
| $ | 3,564 | ||
The Oasis Pipe Line transportation rights was an agreement between Aquila Gas Pipeline and Oasis Pipe Line whereby Aquila Gas Pipeline could elect to reserve a portion of Oasis Pipe Line’s line capacity in advance. The agreement has been amended numerous times, and under the most recent amendment it was cancelable by either party upon ninety days notice and it was scheduled to expire in July 2003. The gathering producer relationships related to certain fixed price gathering contracts that were being amortized over ten years.
11. Investment in Subsidiaries
Oasis Pipe Line
Prior to December 2000, Aquila Gas Pipeline had a 35% interest in Oasis Pipe Line. Thereafter, Aquila Gas Pipeline held 50% of the stock of Oasis Pipe Line. The following table presents financial information related to Oasis Pipe Line for the periods presented:
| Period Ended | ||||||
| September 30, 2002 |
December 31, 2001 | |||||
| (In thousands) | ||||||
| Revenues |
$ | 24,733 | $ | 26,153 | ||
| Total operating expenses |
7,772 | 11,266 | ||||
| Income before income tax expense |
16,700 | 14,707 | ||||
| Net income |
10,850 | 9,556 | ||||
| Pipeline’s share of net income |
5,425 | 4,778 | ||||
| Pipeline’s share of distributions |
4,000 | 1,500 | ||||
| Current assets |
10,680 | 7,061 | ||||
| Total assets |
53,929 | 50,453 | ||||
| Current liabilities |
3,893 | 1,911 | ||||
| Shareholder’s equity |
41,912 | 39,062 | ||||
At September 30, 2002, Aquila Gas Pipeline’s investment exceeded its pro-rata share of Oasis Pipe Line’s equity by $79,792. Prior to 2002, the excess purchase price was being amortized $1,650 per year. In accordance with Aquila Gas Pipeline’s adoption of Statement of Financial Accounting Standards No. 141 and 142, this amortization was ceased effective January 1, 2002.
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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Oasis Pipe Line Company
We have audited the accompanying consolidated balance sheet of Oasis Pipe Line Company and Subsidiaries as of December 27, 2002, and the related consolidated statement of income, shareholders’ equity and cash flow for the period then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oasis Pipe Line Company and Subsidiaries as of December 27, 2002, and the consolidated results of its operations and its cash flows for the period then ended in conformity with U.S. generally accepted accounting principles.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
July 15, 2003
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OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
| December 27, 2002 |
December 31, 2001 |
|||||||
| (unaudited) | ||||||||
| Assets | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 7,962 | $ | 2,352 | ||||
| Accounts receivable—trade (net of allowance for doubtful accounts of $153 in 2002 and $60 in 2001) |
2,290 | 1,997 | ||||||
| Accounts receivable—affiliates |
364 | 552 | ||||||
| Inventories |
1,215 | 1,351 | ||||||
| Refundable income taxes |
— | 540 | ||||||
| Prepaid insurance |
325 | 269 | ||||||
| Total current assets |
12,156 | 7,061 | ||||||
| Property, plant, and equipment: |
||||||||
| Pipeline facilities |
169,308 | 168,745 | ||||||
| Construction-in-progress |
— | 119 | ||||||
| Less accumulated depreciation and amortization |
(127,231 | ) | (125,472 | ) | ||||
| Property, plant, and equipment, net |
42,077 | 43,392 | ||||||
| Other |
413 | — | ||||||
| Total assets |
$ | 54,646 | $ | 50,453 | ||||
| Liabilities and Shareholders’ Equity | ||||||||
| Current liabilities: |
||||||||
| Accounts payable—trade |
$ | 264 | $ | 230 | ||||
| Accounts payable—affiliates |
— | 13 | ||||||
| Accrued liabilities |
376 | 385 | ||||||
| Accrued taxes |
820 | — | ||||||
| Accrued taxes, other than income taxes |
— | 783 | ||||||
| Accrued compensation |
586 | 500 | ||||||
| Total current liabilities |
2,046 | 1,911 | ||||||
| Deferred income taxes |
9,461 | 9,480 | ||||||
| Commitments and contingencies |
||||||||
| Shareholders’ equity: |
||||||||
| Common stock, $1 par value; 50,000 shares authorized and 6,667 shares outstanding |
7 | 7 | ||||||
| Additional paid-in capital |
25,432 | 25,432 | ||||||
| Retained earnings |
35,537 | 31,460 | ||||||
| 60,976 | 56,899 | |||||||
| Less treasury stock, 2,000 shares |
(17,837 | ) | (17,837 | ) | ||||
| Total shareholders’ equity |
43,139 | 39,062 | ||||||
| Total liabilities and shareholders’ equity |
$ | 54,646 | $ | 50,453 | ||||
See accompanying notes.
F-199
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Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands)
| Period Ended December 27, 2002 |
Year Ended December 31, 2001 |
|||||||
| (unaudited) | ||||||||
| Operating revenues: |
||||||||
| Gas transportation—third party |
$ | 23,490 | $ | 15,749 | ||||
| Gas transportation—affiliates |
5,975 | 8,364 | ||||||
| Gas sales—third party |
2,352 | 883 | ||||||
| Fuel and unaccounted for gas |
— | 763 | ||||||
| Other |
914 | 394 | ||||||
| Total operating revenues |
32,731 | 26,153 | ||||||
| Operating expenses: |
||||||||
| Fuel and unaccounted for gas |
133 | — | ||||||
| Operations and maintenance |
4,469 | 4,325 | ||||||
| Depreciation and amortization |
2,106 | 2,458 | ||||||
| Taxes, other than income |
1,207 | 1,171 | ||||||
| Administrative and general |
2,555 | 3,312 | ||||||
| Total operating expenses |
10,470 | 11,266 | ||||||
| Operating income |
22,261 | 14,887 | ||||||
| Other income (expenses): |
||||||||
| Interest income |
64 | 193 | ||||||
| Interest expense—shareholder |
— | (433 | ) | |||||
| Other, net |
(660 | ) | 60 | |||||
| Income before income taxes |
21,665 | 14,707 | ||||||
| Income tax expense |
7,588 | 5,151 | ||||||
| Net income |
$ | 14,077 | $ | 9,556 | ||||
See accompanying notes.
F-200
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Period Ended December 27, 2002 and Year Ended December 31, 2001
(unaudited as to December 31, 2001 data)
| Common Stock |
Treasury Stock |
Additional Paid-in Capital |
Retained |
Total |
|||||||||||||||||
| Shares |
Amount |
Shares |
Amount |
||||||||||||||||||
| (In thousands, except share data) | |||||||||||||||||||||
| Balance at December 31, 2000 |
6,667 | 7 | 2,000 | (17,837 | ) | 25,432 | 24,904 | 32,506 | |||||||||||||
| Net income |
— | — | — | — | — | 9,556 | 9,556 | ||||||||||||||
| Dividends paid ($.45 per share) |
— | — | — | — | — | (3,000 | ) | (3,000 | ) | ||||||||||||
| Balance at December 31, 2001 |
6,667 | 7 | 2,000 | (17,837 | ) | 25,432 | 31,460 | 39,062 | |||||||||||||
| Net income |
— | — | — | — | — | 14,077 | 14,077 | ||||||||||||||
| Dividends paid ($1.50 per share) |
— | — | — | — | — | (10,000 | ) | (10,000 | ) | ||||||||||||
| Balance at December 27, 2002 |
6,667 | $ | 7 | 2,000 | $ | (17,837 | ) | $ | 25,432 | $ | 35,537 | 43,139 | |||||||||
See accompanying notes.
F-201
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Period Ended December 27, 2002 |
Year Ended December 31, 2001 |
|||||||
| (unaudited) | ||||||||
| Operating Activities |
||||||||
| Net income |
$ | 14,077 | $ | 9,556 | ||||
| Reconciliation of net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
2,106 | 2,458 | ||||||
| Deferred income taxes |
(19 | ) | 213 | |||||
| Changes in assets and liabilities that provided (used) cash: |
||||||||
| Accounts receivable |
(105 | ) | (1,744 | ) | ||||
| Inventories |
136 | 120 | ||||||
| Refundable income taxes |
540 | 488 | ||||||
| Accounts payable |
21 | (340 | ) | |||||
| Accrued liabilities |
114 | 96 | ||||||
| Other, net |
(469 | ) | 3 | |||||
| Net cash provided by operating activities |
16,401 | 10,850 | ||||||
| Investing Activities |
||||||||
| Additions to property, plant, and equipment, net |
(791 | ) | (511 | ) | ||||
| Sale of property, plant, and equipment |
— | 5 | ||||||
| Net cash used in investing activities |
(791 | ) | (506 | ) | ||||
| Financing Activities |
||||||||
| Repayment of notes payable—related parties |
— | (11,832 | ) | |||||
| Dividends paid |
(10,000 | ) | (3,000 | ) | ||||
| Note issued to purchase treasury stock |
— | — | ||||||
| Purchase of treasury stock |
— | — | ||||||
| Net cash used in financing activities |
(10,000 | ) | (14,832 | ) | ||||
| Increase (decrease) in cash and cash equivalents |
5,610 | (4,488 | ) | |||||
| Cash and cash equivalents, beginning of year |
2,352 | 6,840 | ||||||
| Cash and cash equivalents, end of year |
$ | 7,962 | $ | 2,352 | ||||
| Supplemental cash flow information: |
||||||||
| Cash paid for income taxes |
7,080 | 4,450 | ||||||
| Cash paid for interest |
— | 433 | ||||||
See accompanying notes.
F-202
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Period Ended December 27, 2002 and Year Ended December 31, 2001
(unaudited as to December 31, 2001 data)
1. Control and Ownership of the Company and Related-Party Transactions
Oasis Pipe Line Company (the “Company”), a Delaware corporation, is engaged in the operation of an intrastate natural gas transmission system in the state of Texas. Immediately prior to December 27, 2002, the Company was owned 50% by a subsidiary of Aquila Gas Pipeline Corporation (Aquila Gas Pipeline), and 50% by Dow Hydrocarbons & Resources, Inc. (“DHRI”). Prior to October 4, 2002, Aquila Gas Pipeline was the wholly owned subsidiary of Aquila, Inc. In October 2002, La Grange Acquisition, L.P. (“La Grange Acquisition”) acquired substantially all the assets of Aquila Gas Pipeline. On December 27, 2002 the Company redeemed all of DHRI’s stock using funds advanced from La Grange Acquisition making the Company a wholly owned subsidiary of La Grange Acquisition.
Before December 28, 2000, ownership was 35% by a subsidiary of Aquila Gas Pipeline, 35% by El Paso Field Services (“EPFS”), and 30% by DHRI. On that date, EPFS sold 5% of its interest to DHRI and the remaining 30% interest was acquired by the Company as treasury stock.
The 2001 financial statements are unaudited, including the disclosure data prior to January 1, 2002.
During 2002, and 2001, the Company derived revenues from its shareholders and their affiliates for the transmission and sale of natural gas. The amount of such net revenues totaled approximately $5,975,000, and $8,364,000, for the years ended December 27, 2002, and December 31, 2001, respectively. Accounts receivable due from affiliates were approximately $364,000 and $552,000 for 2002 and 2001, respectively.
During 2000, the Company reacquired 2,000 previously issued shares of capital stock for $17.8 million. The acquisition was funded with working capital and the borrowing of $11.8 million from shareholders (Aquila Gas Pipeline and DHRI). The borrowings were represented by notes payable bearing interest at 9%. Interest expense associated with the notes payable was $433,000 during 2001. The notes were paid during 2001.
2. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries (collectively, the “Company”). All intercompany accounts and transactions have been eliminated in consolidation. The consolidated financial statements present the financial position and results of operations of the Company prior to its becoming a subsidiary of La Grange Acquisition and therefore exclude the purchase adjustments relating to the redemption and intercompany promissory note on December 27, 2002 (see Note 6).
Inventories
The Company requires its customers to provide additional gas, based on predetermined quantities of gas to be delivered, for fuel. If the gas is in excess of the Company’s needs, the Company can retain the excess gas or sell it to third parties. If additional fuel is required, the Company will purchase additional volumes in the market. Inventories represent the gas that is retained. The Company values inventories at the lower of cost or market as of the balance sheet dates.
Property, Plant, and Equipment
Normal maintenance that does not add capacity or extend the useful life of the equipment and repairs of property, plant, and equipment are charged to expense as incurred. Improvements that materially extend the useful lives of the assets are capitalized, and the assets replaced, if any, are retired. When capital assets are
F-203
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Period Ended December 27, 2002 and Year Ended December 31, 2001
(unaudited as to December 31, 2001 data)
retired or replaced, the balance of the assets and the accumulated depreciation are removed and any gain or loss upon disposition is included in income. Fixed assets of approximately $346,000 and $134,000 were retired during 2002 and 2001, respectively.
Depreciation is computed using the straight-line method of accounting over the estimated useful lives of the related assets. Annual depreciable lives range from 5 to 85 years.
The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amounts of those assets.
Environmental Expenditures
Environmental related restoration and remediation costs are recorded as liabilities and expensed when site restoration and environmental remediation and cleanup obligations are either known or considered probable and the related costs can be reasonably estimated.
Income Taxes
The Company recognizes deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial accounting bases and the tax bases of assets and liabilities. The deferred tax effects of these temporary differences are calculated using the tax rates currently in effect.
Revenue Recognition
Transportation revenue is recognized as transportation is provided. Capacity payments are recognized when earned in the period capacity was made available.
Financial Instruments and Credit Risk
The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, and accounts payable. The carrying value of the Company’s financial instruments approximates fair value due to their short-term nature. The Company considers all investments with maturities of three months or less at acquisition to be cash equivalents. The Company’s receivables are generally from entities involved in the energy industry or significant industrial customers. The Company specifically reviews all its receivables in determining its allowance for doubtful accounts and the receivables are generally unsecured.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Reclassifications
Certain reclassifications have been made to the 2001 financial statements to conform to the 2002 presentation.
F-204
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Period Ended December 27, 2002 and Year Ended December 31, 2001
(unaudited as to December 31, 2001 data)
3. Income Taxes
Components of income tax provision/(benefit) attributable to income before taxes are as follows:
| December 27, 2002 |
December 31, 2001 | ||||||
| Current |
$ | 7,607 | $ | 4,938 | |||
| Deferred |
(19 | ) | 213 | ||||
| Total income tax expense |
$ | 7,588 | $ | 5,151 | |||
The tax provision effective rate for December 27, 2002 and December 31, 2001 was 35%.
Deferred income taxes consist of the following:
| December 27, 2002 |
December 31, 2001 |
|||||||
| Property, plant and equipment |
$ | (9,178 | ) | $ | (9,131 | ) | ||
| Other |
(283 | ) | (349 | ) | ||||
| Net deferred tax liabilities |
$ | (9,461 | ) | $ | (9,480 | ) | ||
4. Employee Benefit Plan
An employee savings plan is available to all permanent employees, effective the first day of their employment. For every $1 each employee contributes, the Company matches $1, not to exceed 5% of each employee’s salary subject to the maximum contribution allowed by law. Each employee is fully vested on his or her first day of employment. The Company expensed contributions of approximately $144,000 and $140,000 for 2002 and 2001, respectively.
5. Contingencies
The Company is subject to federal, state and local environmental laws and regulations, which generally require expenditures for remediation at operating facilities and waste disposal sites. At December 27, 2002 and December 31, 2001, the Company had reserved approximately $252,000 and $292,000 respectively, for the expected costs of complying with such laws and regulations. These expected costs are primarily related to properties previously owned and are recorded on the consolidated balance sheets as accrued liabilities based upon management’s estimates of the timing of the expenditure. The purchase and sale agreement between La Grange Acquisition and Aquila Gas Pipeline requires Aquila, Inc. to reimburse Oasis for 50% of any remediation expenditures related to operations prior to October 1, 2002.
On June 16, 2003, Guadalupe Power Partners, L.P. (GPP) sought and obtained a Temporary Restraining Order against Oasis Pipe Line. In their pleadings, GPP alleged unspecified monetary damages for the period from February 25, 2003 to June 16, 2003 and sought to prevent Oasis Pipe Line from implementing flow control measures to reduce the flow of gas to their power plant at varying hourly rates. Oasis Pipe Line filed a counterclaim against GPP asking for damages and a declaration that the contract was terminated as a result of the breach by GPP. Oasis Pipe Line and GPP agreed to a “stand still” order and referred this dispute to binding arbitration. Oasis Pipe Line has retained trial counsel to defend this matter and a date for the commencement of the arbitration proceedings has not yet been set.
F-205
Table of Contents
Index to Financial Statements
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Period Ended December 27, 2002 and Year Ended December 31, 2001
(unaudited as to December 31, 2001 data)
The Company is also party to legal actions that have arisen in the ordinary course of its business. Due to the inherent uncertainty of litigation, the range of any possible loss cannot be estimated with a reasonable degree of precision.
6. Stock Redemption
On December 27, 2002, the Company purchased 50% of its capital stock owned by DHRI for $87 million. The Company funded the acquisition by borrowing $87 million from La Grange Acquisition evidenced by a promissory note (the “Note”). Effective with the redemption, the Company became a wholly owned subsidiary of La Grange Acquisition and is included in the financial statements of La Grange Acquisition effective December 27, 2002. The Note bears interest at an annual rate of 8.5% with payments of $1.6 million due monthly until final maturity on February 1, 2006 at which time the remaining balance will be due. The consolidated financial statements present the financial position and results of operations of the Company prior to its becoming a subsidiary of LaGrange Acquisition and therefore exclude the purchase adjustments relating to the redemption and intercompany promissory note on December 27, 2002.
F-206
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Partners, L.P.
We have audited the accompanying consolidated balance sheet of Heritage Propane Partners, L.P. (a Delaware limited partnership) and subsidiaries as of August 31, 2003 and the related consolidated statements of operations, comprehensive income, partners’ capital, and cash flows for the period ended January 19, 2004 and for the years ended August 31, 2003 and 2002. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Heritage Propane Partners, L.P. and subsidiaries as of August 31, 2003 and the results of their operations and their cash flows for the period ended January 19, 2004 and for the years ended August 31, 2003 and 2002, in conformity with accounting principles generally accepted in the United States of America.
As explained in Note 2 to the consolidated financial statements, effective September 1, 2002, the Partnership changed its method of accounting for stock-based compensation plans and adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation following the modified prospective method of adoption described in Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure.
/s/ Grant Thornton LLP
Tulsa, Oklahoma
November 11, 2004
F-207
Table of Contents
Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED BALANCE SHEET
(in thousands, except unit data)
| August 31, 2003 |
||||
| ASSETS | ||||
| CURRENT ASSETS: |
||||
| Cash and cash equivalents |
$ | 7,117 | ||
| Marketable securities |
3,044 | |||
| Accounts receivable, net of allowance for doubtful accounts |
35,879 | |||
| Inventories |
45,274 | |||
| Assets from liquids marketing |
83 | |||
| Prepaid expenses and other |
2,741 | |||
| Total current assets |
94,138 | |||
| PROPERTY, PLANT AND EQUIPMENT, Net |
426,588 | |||
| INVESTMENT IN AFFILIATES |
8,694 | |||
| GOODWILL |
156,595 | |||
| INTANGIBLES AND OTHER ASSETS, Net |
52,824 | |||
| Total assets |
$ | 738,839 | ||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||
| CURRENT LIABILITIES: |
||||
| Working capital facility |
$ | 26,700 | ||
| Accounts payable |
43,690 | |||
| Accounts payable to related companies |
6,255 | |||
| Accrued and other current liabilities |
35,993 | |||
| Liabilities from liquids marketing |
80 | |||
| Current maturities of long-term debt |
38,309 | |||
| Total current liabilities |
151,027 | |||
| LONG-TERM DEBT, less current maturities |
360,762 | |||
| MINORITY INTERESTS |
4,002 | |||
| 515,791 | ||||
| COMMITMENTS AND CONTINGENCIES |
||||
| PARTNERS’ CAPITAL: |
||||
| Common Unitholders (18,013,229 units issued and outstanding) |
221,207 | |||
| Class C Unitholders (1,000,000 units issued and outstanding) |
— | |||
| General Partner |
2,190 | |||
| Accumulated other comprehensive loss |
(349 | ) | ||
| Total partners’ capital |
223,048 | |||
| Total liabilities and partners’ capital |
$ | 738,839 | ||
The accompanying notes are an integral part of these consolidated financial statements.
F-208
Table of Contents
Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit and unit data)
| For the Period Ended January 19, 2004 |
For the Years Ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| REVENUES: |
||||||||||||
| Retail fuel |
$ | 221,459 | $ | 463,392 | $ | 365,334 | ||||||
| Wholesale fuel |
20,596 | 47,366 | 41,204 | |||||||||
| Liquids marketing, net |
369 | 1,333 | 542 | |||||||||
| Other |
27,928 | 59,385 | 55,245 | |||||||||
| Total revenues |
270,352 | 571,476 | 462,325 | |||||||||
| COSTS AND EXPENSES: |
||||||||||||
| Cost of products sold |
148,329 | 297,156 | 238,185 | |||||||||
| Operating expenses |
60,735 | 152,131 | 133,203 | |||||||||
| Depreciation and amortization |
15,389 | 37,959 | 36,998 | |||||||||
| Selling, general and administrative |
10,100 | 14,037 | 12,978 | |||||||||
| Total costs and expenses |
234,553 | 501,283 | 421,364 | |||||||||
| OPERATING INCOME |
35,799 | 70,193 | 40,961 | |||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||
| Interest expense |
(12,754 | ) | (35,740 | ) | (37,341 | ) | ||||||
| Equity in earnings of affiliates |
496 | 1,371 | 1,338 | |||||||||
| Gain (loss) on disposal of assets |
(240 | ) | 430 | 812 | ||||||||
| Other |
(66 | ) | (3,213 | ) | (294 | ) | ||||||
| INCOME BEFORE MINORITY INTERESTS AND INCOME TAXES |
23,235 | 33,041 | 5,476 | |||||||||
| Minority interests |
(572 | ) | (876 | ) | (574 | ) | ||||||
| NET INCOME BEFORE INCOME TAXES |
22,663 | 32,165 | 4,902 | |||||||||
| Income taxes |
20 | 1,023 | — | |||||||||
| NET INCOME |
22,643 | 31,142 | 4,902 | |||||||||
| GENERAL PARTNER’S INTEREST IN NET INCOME |
551 | 1,319 | 918 | |||||||||
| LIMITED PARTNERS’ INTEREST IN NET INCOME |
$ | 22,092 | $ | 29,823 | $ | 3,984 | ||||||
| BASIC NET INCOME PER LIMITED PARTNER UNIT |
$ | 1.21 | $ | 1.79 | $ | 0.25 | ||||||
| BASIC AVERAGE NUMBER OF UNITS OUTSTANDING |
18,286,352 | 16,635,966 | 15,738,621 | |||||||||
| DILUTED NET INCOME PER LIMITED PARTNER UNIT |
$ | 1.21 | $ | 1.79 | $ | 0.25 | ||||||
| DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING |
18,333,036 | 16,694,343 | 15,777,307 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-209
Table of Contents
Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
| For the Period Ended January 19, 2004 |
For the Years Ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| Net income |
$ | 22,643 | $ | 31,142 | $ | 4,902 | ||||||
| Other comprehensive income (loss) |
||||||||||||
| Reclassification adjustment for losses or gains on derivative instruments included in net income |
— | (553 | ) | — | ||||||||
| Reclassification adjustment for losses on available-for-sale securities included in net income |
— | 2,823 | — | |||||||||
| Change in value of derivative instruments |
— | 553 | 4,464 | |||||||||
| Change in value of available-for-sale securities |
(533 | ) | 480 | (1,575 | ) | |||||||
| Comprehensive income |
$ | 22,110 | $ | 34,445 | $ | 7,791 | ||||||
| Reconciliation of Accumulated Other Comprehensive Loss |
||||||||||||
| Balance, beginning of period |
$ | (349 | ) | $ | (3,652 | ) | $ | (6,541 | ) | |||
| Current period reclassification to earnings |
— | 2,270 | 7,016 | |||||||||
| Current period change |
(533 | ) | 1,033 | (4,127 | ) | |||||||
| Balance, end of period |
$ | (882 | ) | $ | (349 | ) | $ | (3,652 | ) | |||
The accompanying notes are an integral part of these consolidated financial statements.
F-210
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except unit data)
| Number of Units |
Common |
Class B Subordinated |
Class C |
General Partner |
Accumulated Other Income (Loss) |
Total |
|||||||||||||||||||||||||
| Common |
Class B Subordinated |
Class C |
|||||||||||||||||||||||||||||
| Balance, August 31, 2001 |
14,260,316 | 1,382,514 | 1,000,000 | $ | 190,548 | $ | 15,532 | $ | — | $ | 1,875 | $ | (6,541 | ) | $ | 201,414 | |||||||||||||||
| Unit distribution |
— | — | — | (38,159 | ) | (1,746 | ) | — | (1,240 | ) | — | (41,145 | ) | ||||||||||||||||||
| Conversion of Phantom Units |
11,750 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Conversion of Subordinated Units |
1,382,514 | (1,382,514 | ) | — | 15,137 | (15,137 | ) | — | — | — | — | ||||||||||||||||||||
| Issuance of units upon conversion of minority interest |
162,913 | — | — | 1,729 | — | — | — | — | 1,729 | ||||||||||||||||||||||
| General Partner capital contribution |
(1,646 | ) | — | — | (32 | ) | — | — | 32 | — | — | ||||||||||||||||||||
| Net change in accumulated other comprehensive loss per accompanying statements |
— | — | — | — | — | — | — | 2,889 | 2,889 | ||||||||||||||||||||||
| Other |
— | — | — | 1,821 | — | — | — | — | 1,821 | ||||||||||||||||||||||
| Net income |
— | — | — | 2,633 | 1,351 | — | 918 | — | 4,902 | ||||||||||||||||||||||
| Balance, August 31, 2002 |
15,815,847 | — | 1,000,000 | 173,677 | — | — | 1,585 | (3,652 | ) | 171,610 | |||||||||||||||||||||
| Unit distribution |
— | — | — | (42,042 | ) | — | — | (1,342 | ) | — | (43,384 | ) | |||||||||||||||||||
| Issuance of Common Units |
1,610,000 | 44,547 | 44,547 | ||||||||||||||||||||||||||||
| Conversion of Phantom Units |
2,500 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Issuance of Common Units in connection with the Long-term incentive plan |
66,118 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Issuance of Common Units in connection with certain acquisitions |
551,456 | — | — | 15,000 | — | — | — | — | 15,000 | ||||||||||||||||||||||
| General Partner capital contribution |
(32,692 | ) | — | — | (957 | ) | — | — | 628 | — | (329 | ) | |||||||||||||||||||
| Net change in accumulated other comprehensive loss per accompanying statements |
— | — | — | — | — | — | — | 3,303 | 3,303 | ||||||||||||||||||||||
| Other |
— | — | — | 1,159 | — | — | — | — | 1,159 | ||||||||||||||||||||||
| Net income |
— | — | — | 29,823 | — | — | 1,319 | — | 31,142 | ||||||||||||||||||||||
| Balance, August 31, 2003 |
18,013,229 | — | 1,000,000 | 221,207 | — | — | 2,190 | (349 | ) | 223,048 | |||||||||||||||||||||
| Unit distribution |
— | — | — | (23,696 | ) | — | — | (887 | ) | — | (24,583 | ) | |||||||||||||||||||
| Conversion of Phantom Units |
14,800 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Issuance of Common Units in connection with certain acquisitions |
505,826 | — | — | 17,116 | — | — | — | — | 17,116 | ||||||||||||||||||||||
| General Partner capital contribution |
— | — | — | — | — | — | 180 | — | 180 | ||||||||||||||||||||||
| Net change in accumulated other comprehensive loss per accompanying statements |
— | — | — | — | — | — | — | (533 | ) | (533 | ) | ||||||||||||||||||||
| Other |
— | — | — | 1,232 | — | — | — | 1,232 | |||||||||||||||||||||||
| Net income |
— | — | — | 22,092 | — | 551 | — | 22,643 | |||||||||||||||||||||||
| Balance, January 19, 2004 |
18,533,855 | — | 1,000,000 | $ | 237,951 | $ | $ | — | $ | 2,034 | $ | (882 | ) | $ | 239,103 | ||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| For the Period 2004 |
For the Years Ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
| Net income |
$ | 22,643 | $ | 31,142 | $ | 4,902 | ||||||
| Reconciliation of net income to net cash provided by operating activities |
||||||||||||
| Depreciation and amortization |
15,389 | 37,959 | 36,998 | |||||||||
| Provision for loss on accounts receivable |
449 | 2,578 | 887 | |||||||||
| Loss on write down of marketable securities |
— | 2,823 | — | |||||||||
| (Gain) loss on disposal of assets |
240 | (430 | ) | (812 | ) | |||||||
| Deferred compensation on restricted units and long-term incentive plan |
1,232 | 1,159 | 1,878 | |||||||||
| Undistributed earnings of affiliates |
(35 | ) | (836 | ) | (938 | ) | ||||||
| Minority interests |
491 | (48 | ) | (111 | ) | |||||||
| Changes in assets and liabilities, net of effect of acquisitions: |
||||||||||||
| Accounts receivable |
(29,745 | ) | (4,066 | ) | 9,180 | |||||||
| Inventories |
(37,850 | ) | 4,855 | 17,827 | ||||||||
| Assets from liquids marketing |
82 | 2,218 | 4,164 | |||||||||
| Prepaid and other expenses |
(6,262 | ) | 4,177 | 8,086 | ||||||||
| Intangibles and other assets |
(2,019 | ) | 238 | 1,197 | ||||||||
| Accounts payable |
56,296 | 3,115 | (4,094 | ) | ||||||||
| Accounts payable to related companies |
(6,620 | ) | 1,253 | (2,935 | ) | |||||||
| Accrued and other current liabilities |
555 | 10,800 | (5,464 | ) | ||||||||
| Liabilities from liquids marketing |
(80 | ) | (1,738 | ) | (5,312 | ) | ||||||
| Net cash provided by operating activities |
14,766 | 95,199 | 65,453 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
| Cash paid for acquisitions, net of cash acquired |
(22,490 | ) | (24,956 | ) | (19,742 | ) | ||||||
| Capital expenditures |
(19,760 | ) | (27,294 | ) | (27,072 | ) | ||||||
| Proceeds from the sale of assets |
772 | 3,861 | 13,336 | |||||||||
| Investment in marketable securities |
— | — | (29 | ) | ||||||||
| Other |
— | — | 95 | |||||||||
| Net cash used in investing activities |
(41,478 | ) | (48,389 | ) | (33,412 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
| Proceeds from borrowings |
239,359 | 173,678 | 164,715 | |||||||||
| Principal payments on debt |
(170,539 | ) | (219,282 | ) | (156,584 | ) | ||||||
| Net proceeds from issuance of Common Units |
— | 44,547 | — | |||||||||
| Unit distributions |
(24,583 | ) | (43,384 | ) | (41,145 | ) | ||||||
| Other |
180 | 152 | (57 | ) | ||||||||
| Net cash provided by (used in) financing activities |
44,417 | (44,289 | ) | (33,071 | ) | |||||||
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
17,705 | 2,521 | (1,030 | ) | ||||||||
| CASH AND CASH EQUIVALENTS, beginning of period |
7,117 | 4,596 | 5,626 | |||||||||
| CASH AND CASH EQUIVALENTS, end of period |
$ | 24,822 | $ | 7,117 | $ | 4,596 | ||||||
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)
(in thousands)
| For the Period 2004 |
For the Years Ended August 31, | ||||||||
| 2003 |
2002 | ||||||||
| NONCASH FINANCING ACTIVITIES: |
|||||||||
| Notes payable incurred on noncompete agreements |
$ | 6,914 | $ | 948 | $ | 2,737 | |||
| Issuance of Common Units in connection with certain acquisitions |
$ | 17,116 | $ | 15,000 | $ | — | |||
| Issuance of Common Units upon conversion of minority interest |
$ | — | $ | — | $ | 1,729 | |||
| General Partner capital contribution |
$ | — | $ | 329 | $ | — | |||
| Conversion of equity investment in Bi State Partnership to wholly owned subsidiary upon purchase of remaining 50% that was not previously owned by Heritage |
$ | 8,249 | $ | — | $ | — | |||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
|||||||||
| Cash paid during the period for interest |
$ | 12,261 | $ | 35,315 | $ | 37,610 | |||
| Cash paid during the period for income taxes |
$ | 46 | $ | 523 | $ | — | |||
The accompanying notes are an integral part of these financial statements
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except unit and per unit data)
1. OPERATIONS AND ORGANIZATION:
Energy Transfer Transactions
On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage in exchange for cash of $300,000 less the amount of Energy Transfer Company debt in excess of $151,500, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433,909 of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151,500. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 Special Units as consideration for the project it had in progress to construct the Bossier Pipeline.
Simultaneously with the Energy Transfer Transactions, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane, L.P.’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30,000 (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane L.P. contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (“HOLP”) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) for $100,000.
Concurrent with the Energy Transfer Transactions, La Grange Acquisition borrowed $325,000 from financial institutions and Heritage raised $355,948 of gross proceeds net of underwriter’s discount through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes.
Accounting treatment of the Energy Transfer Transactions
The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS 141. Although Heritage Propane Partners, L.P. is the surviving parent entity for legal purposes, ETC OLP is the acquirer for accounting purposes. As a result, ETC OLP’s historical financial statements are now the historical financial statements of the registrant. The operations of Heritage Propane Partners, L.P. prior to the ETC OLP Transaction are referred to as “Heritage.” On February 12, 2004, the Board of Directors of Heritage Propane Partners, L.P.’s General Partner voted to change the name of Heritage Propane Partners, L.P. to Energy Transfer Partners, L.P. The assets and liabilities and results of operations of Heritage as of January 19, 2004 are included in the financial statements of the surviving parent entity, Energy Transfer Partners, L.P.
Business Operations
In order to simplify the Heritage’s obligations under the laws of several jurisdictions in which it conducts business, the Partnership’s activities are conducted through a subsidiary operating partnership, Heritage Operating, L.P. (the “Operating Partnership”). The Partnership and the Operating Partnership are collectively referred to in this report as Heritage. Heritage sells propane and propane-related products to more than 650,000
F-214
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
active residential, commercial, industrial, and agricultural customers from over 310 customer service locations in 32 states. Heritage is also a wholesale propane supplier in the United States and in Canada, the latter through participation in MP Energy Partnership. MP Energy Partnership is a Canadian partnership, in which Heritage owns a 60% interest, engaged in lower-margin wholesale distribution and in supplying Heritage’s northern U.S. locations. Heritage buys and sells financial instruments for its own account through its wholly owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Principles of Consolidation
The consolidated financial statements of Heritage include the accounts of its subsidiaries, including Heritage Operating and its subsidiaries. At August 31, 2003, Heritage accounted for its 50% partnership interest in Bi-State Propane, (“Bi-State”) a propane retailer in the states of Nevada and California, under the equity method. On December 24, 2003, Heritage acquired the remaining 50% of Bi-State that it did not previously own, thereby making Bi-State a wholly owned subsidiary of Heritage.
For purposes of maintaining partner capital accounts, the Partnership Agreement of Heritage (the “Partnership Agreement”) specifies that items of income and loss shall be allocated among the partners in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to the General Partner. The 1.0101% general partner interest in the Operating Partnership held by the General Partner, U.S. Propane, L.P. (“U.S. Propane”), is accounted for in the consolidated financial statements of Heritage as a minority interest.
Revenue Recognition
Sales of propane, propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor is recognized upon completion of the service and tank rent is recognized ratably over the period it is earned. Shipping and handling revenues are included in the price of propane charged to customers, and thus are classified as revenues.
Costs and Expenses
Costs of products sold include actual cost of fuel sold adjusted for the effects of qualifying cash flow hedges, storage fees and inbound freight, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs, purchasing costs, and plant operations. Selling, general and administrative expenses include all corporate expenses and compensation for corporate personnel.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. Heritage considers cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Marketable Securities
Heritage’s marketable securities are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at their fair value. During the year ended August 31, 2003, Heritage determined there was a non-temporary decline in the market value of its available-for-sale securities, and reclassified into earnings a loss of $2,823, which is net of minority interest and is recorded in other expense. Unrealized holding gains (losses) of $480 and $(1,575) for the years ended August 31, 2003 and 2002, respectively, were recorded through accumulated other comprehensive income (loss) based on the market value of the securities.
Accounts Receivable
Heritage grants credit to its customers for the purchase of propane and propane-related products. Accounts receivable are recorded at amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of Heritage’s customers and any specific disputes. Heritage recorded bad debt expense net of recoveries of $449, $2,578 and $887, for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively. Accounts receivable consisted of the following:
| August 31, 2003 | |||
| Accounts receivable |
$ | 39,383 | |
| Less—allowance for doubtful accounts |
3,504 | ||
| Total, net |
$ | 35,879 | |
The activity in the allowance for doubtful accounts consisted of the following:
| Period Ended 2004 |
Years Ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| Balance, beginning of the period |
$ | 3,504 | $ | 2,504 | $ | 3,576 | ||||||
| Provision for loss on accounts receivable |
449 | 2,578 | 887 | |||||||||
| Accounts receivable written off, net of recoveries |
(449 | ) | (1,578 | ) | (1,959 | ) | ||||||
| Balance, end of period |
$ | 3,504 | $ | 3,504 | $ | 2,504 | ||||||
Inventories
Inventories are valued at the lower of cost or market. The cost of fuel inventories is determined using weighted-average cost of fuel delivered to the retail districts and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:
| August 31, 2003 | |||
| Fuel |
$ | 34,544 | |
| Appliances, parts and fittings |
10,730 | ||
| Total inventories |
$ | 45,274 | |
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish tanks that either extend the useful lives of the tanks or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the tanks. Additionally, Heritage capitalizes certain costs directly related to the installation of company-owned tanks, including internal labor costs. Components and useful lives of property, plant and equipment were as follows:
| August 31, 2003 |
||||
| Land and improvements |
$ | 21,937 | ||
| Buildings and improvements (10 to 30 years) |
30,843 | |||
| Bulk storage, equipment and facilities (3 to 30 years) |
43,340 | |||
| Tanks and other equipment (5 to 30 years) |
327,193 | |||
| Vehicles (5 to 10 years) |
76,239 | |||
| Furniture and fixtures (3 to 10 years) |
11,164 | |||
| Other (5 to 10 years) |
3,578 | |||
| 514,294 | ||||
| Less—Accumulated depreciation |
(99,563 | ) | ||
| 414,731 | ||||
| Plus—Construction work-in-process |
11,857 | |||
| Property, plant and equipment, net |
$ | 426,588 | ||
Intangibles and Other Assets
Intangibles and other assets are stated at cost net of amortization computed on the straight-line method. Heritage eliminates from its balance sheet any fully amortized intangibles and the related accumulated amortization. Components and useful lives of intangibles and other assets were as follows:
| August 31, 2003 |
|||||||
| Gross Carrying Amount |
Accumulated Amortization |
||||||
| Amortized intangible assets |
|||||||
| Noncompete agreements (5 to 15 years) |
$ | 42,742 | $ | (15,893 | ) | ||
| Customer lists (15 years) |
28,378 | (6,356 | ) | ||||
| Financing costs (3 to 15 years) |
4,225 | (1,995 | ) | ||||
| Consulting agreements (2 to 7 years) |
517 | (367 | ) | ||||
| Total |
75,862 | (24,611 | ) | ||||
| Unamortized intangible assets |
|||||||
| Trademarks |
1,309 | — | |||||
| Other assets |
264 | — | |||||
| Total intangibles and other assets |
$ | 77,435 | $ | (24,611 | ) | ||
Aggregate amortization expense of intangible assets was $2,927, $7,811, and $8,152 for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Goodwill
Goodwill is associated with acquisitions made for Heritage’s domestic retail segment; therefore, all goodwill is recorded in this segment. Of the $156,595 balance in goodwill, $23,923 is expected to be tax deductible. Goodwill is tested for impairment at the end of each fiscal year end in accordance with SFAS 142. The changes in the carrying amount of goodwill for the year ended August 31, 2003 were as follows:
| Balance as of August 31, 2002 |
155,735 | |
| Goodwill acquired during the year |
860 | |
| Impairment losses |
— | |
| Balance as of August 31, 2003 |
156,595 | |
Long-Lived Assets
Heritage reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, Heritage reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the period ended January 19, 2004, or the years ended August 31, 2003 and 2002.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
| August 31, 2003 | |||
| Interest payable |
$ | 4,485 | |
| Wages and payroll taxes |
4,932 | ||
| Deferred tank rent |
4,080 | ||
| Advanced budget payments and unearned revenue |
15,417 | ||
| Customer deposits |
2,137 | ||
| Taxes other than income |
2,405 | ||
| Income taxes |
500 | ||
| Other |
2,037 | ||
| Accrued and other current liabilities |
$ | 35,993 | |
Income Taxes
Heritage is a master limited partnership. As a result, Heritage’s earnings or losses for federal and state income tax purposes are included in the tax returns of the individual partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements of Heritage except those incurred by corporate subsidiaries of Heritage that are subject to income taxes. On May 31, 2003 Guilford Gas Service, Inc., one of the Heritage’s taxable subsidiaries was merged with the Operating Partnership. Taxes recorded in connection with this liquidation were approximately $250. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement. As of August 31, 2003 there was a liability of $500 recorded for income taxes incurred by Heritage’s corporate subsidiaries.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Income Per Limited Partner Unit
Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding. Diluted net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding and, if dilutive, the weighted average number of restricted units (“Phantom Units”) outstanding under the Restricted Unit Plan. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
| Period Ended 2004 |
Years Ended August 31, | ||||||||
| 2003 |
2002 | ||||||||
| Basic Net Income per Limited Partner Unit: |
|||||||||
| Limited Partners’ interest in net income |
$ | 22,092 | $ | 29,823 | $ | 3,984 | |||
| Weighted average limited partner units |
18,286,352 | 16,635,966 | 15,738,621 | ||||||
| Basic net income per limited partner unit |
$ | 1.21 | $ | 1.79 | $ | 0.25 | |||
| Diluted Net Income per Limited Partner Unit: |
|||||||||
| Limited partners’ interest in net income |
$ | 22,092 | $ | 29,823 | $ | 3,984 | |||
| Weighted average limited partner units |
18,286,352 | 16,635,966 | 15,738,621 | ||||||
| Dilutive effect of phantom units |
46,684 | 58,377 | 38,686 | ||||||
| Weighted average limited partner units, assuming dilutive effect of phantom units |
18,333,036 | 16,694,343 | 15,777,307 | ||||||
| Diluted net income per limited partner unit |
$ | 1.21 | $ | 1.79 | $ | 0.25 | |||
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Some of the more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, derivative hedging instruments, liquids marketing assets and liabilities, purchase accounting allocations and subsequent realizability of intangible assets, and general business and medical self-insurance reserves. Actual results could differ from those estimates.
Fair Value
The carrying amounts of accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to Heritage for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2003 was $421,579 and $399,071, respectively.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Stock Based Compensation Plans
During the fourth quarter of 2003, Heritage adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 Accounting for Stock-based Compensation (SFAS 123) effective as of September 1, 2002. Heritage applied the fair value recognition provisions following the modified prospective method of adoption described in Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure (SFAS 148).
SFAS 123 requires that significant assumptions be used during the year to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the grants. Heritage assumed a weighted average risk free interest rate of 6.29% for the period ended January 19, 2004, 5.72% for the year ended August 31, 2003, and 6.18% for the year ended August 31, 2002 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. Annual average cash distributions at the grant date were estimated to be $2.70 for the period ended January 19, 2004, $2.39 for the year ended August 31, 2003, and $2.37 for the year ended August 31, 2002. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant.
Accounting for Derivative Instruments and Hedging Activities
Heritage applies Financial Accounting Standards Board (“FASB”) Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS 133 requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. There were no such financial instruments outstanding as of August 31, 2003.
Heritage buys and sells derivative financial instruments, which are within the scope of SFAS 133 and that are not designated as accounting hedges. Heritage also enters into energy trading contracts, which are not derivatives, and therefore are not within the scope of SFAS 133. EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10), applied to energy trading contracts not within the scope of SFAS 133 that were entered into prior to October 25, 2002. The types of contracts Heritage utilizes in its liquids marketing segment include energy commodity forward contracts, options, and swaps traded on the over-the-counter financial markets. In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with Heritage’s liquids marketing activity are accounted for using the mark-to-market method. Additionally, all energy trading contracts entered into prior to October 25, 2002 were accounted for using the mark-to-market method in accordance with the provisions of EITF 98-10. Under the mark-to-market method of accounting, forwards, swaps, options, and storage contracts are reflected at fair value, and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. As of August 31, 2002, Heritage adopted the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as liquids marketing revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. EITF 02-3 also rescinds EITF 98-10 for all energy trading contracts entered into after October 25, 2002 and specifies certain disclosure requirements. Consequently, Heritage does not apply mark-to-market accounting for
F-220
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
any contracts entered into after October 25, 2002, that are not within the scope of SFAS 133. Heritage attempts to balance its contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on management’s assessment of anticipated market movements.
The notional amounts and terms of these financial instruments as of August 31, 2003 include fixed price payor for 45 barrels of propane and fixed price receiver of 195 barrels of propane, respectively. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Heritage’s exposure to market or credit risks.
Estimates related to Resource’s liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $345 change in the market value of the contracts as there were approximately 6.3 million gallons of net unbalanced positions at August 31, 2003.
Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract. Heritage and Resources take active roles in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. Heritage monitors market risk through a variety of techniques, including routine reporting to senior management. Heritage attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures.
The following table summarizes the fair value of Resources’ contracts, aggregated by method of estimating fair value of the contracts as of August 31, 2003 where settlement had not yet occurred. Resources’ contracts all have a maturity of less than 1 year. The market prices used to value these transactions reflect management’s best estimate considering various factors including closing average spot prices for the current and outer months plus a differential to consider time value and storage costs.
| August 31, 2003 | |||
| Source of Fair Value |
|||
| Prices actively quoted |
$ | 80 | |
| Prices based on other valuation methods |
3 | ||
| Assets from liquids marketing |
$ | 83 | |
| Prices actively quoted |
$ | 80 | |
| Prices based on other valuation methods |
— | ||
| Liabilities from liquids marketing |
$ | 80 | |
| Unrealized gains (losses) |
$ | 3 | |
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
The following table summarizes the changes in the unrealized fair value of Resources’ contracts where settlement had not yet occurred for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002.
| January 19, 2004 |
August 31, 2003 |
August 31, 2002 |
||||||||
| Unrealized gains (losses) in fair value of contracts outstanding at the beginning of the period |
$ | 3 | $ | 483 | $ | (665 | ) | |||
| Unrealized gains (losses) recognized at inception of contracts |
— | — | — | |||||||
| Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions |
— | — | — | |||||||
| Other unrealized gains (losses) recognized during the period |
366 | 850 | 1,207 | |||||||
| Less: Realized gains (losses) recognized during the period |
369 | 1,330 | 59 | |||||||
| Unrealized gains (losses) in fair value of contracts outstanding at the end of the period |
$ | — | $ | 3 | $ | 483 | ||||
The following table summarizes the gross transaction volumes in barrels for liquids marketing contracts that were physically settled for the period ended January 19, 2004 and the years ended August 31, 2003, and 2002:
| (In thousands) | ||
| Period ended January 19, 2004 |
29 | |
| Fiscal year ended August 31, 2003 |
181 | |
| Fiscal year ended August 31, 2002 |
350 |
3. Acquisitions:
During the period ended January 19, 2004, Heritage acquired the assets of Big Sky Petroleum, Archibald Propane, Moore-L.P. Gas, Inc., Sunbeam L.P., Gas, Inc. Metro Lift Propane, and two other small companies. Heritage also acquired the 50% interest in Bi-State Propane that it did not previously own. The aggregate purchase price for these acquisitions was $47,989 which included $22,490 in cash, $17,116 in Common Units issued, and $8,383 liabilities assumed and non-compete agreements.
On January 2, 2003, Heritage purchased the propane assets of V-1 Oil Co. (“V-1”) of Idaho Falls, Idaho for total consideration of $35.4 million after post-closing adjustments. The acquisition price was payable $20.0 million in cash, with $17.3 million of that amount financed by the Acquisition Facility, and by the issuance of 551,456 Common Units of Heritage valued at $15.0 million, and assumed $0.4 million in liabilities. V-1’s propane distribution network included 35 customer service locations in Colorado, Idaho, Montana, Oregon, Utah, Washington, and Wyoming. Heritage was able to expand its market presence in the Northwest and achieve a greater geographical balance through the transaction with V-1. This acquisition enhanced Heritage’s current operations and reduced costs through synergies with existing operations in locations in which Heritage was already conducting business. The results of operations of V-1 from January 2, 2003 to August 31, 2003 are included in the consolidated statement of operations of Heritage for the year ended August 31, 2003.
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
The following unaudited pro forma consolidated results of operations are presented as if the acquisition of V-1 had been made at the beginning of the period presented:
| Year ended August 31, 2003 |
Year ended August 31, 2002 | |||||
| Total revenues |
$ | 582,690 | $ | 494,805 | ||
| Limited partners’ interest in net income |
$ | 31,430 | $ | 6,806 | ||
| Basic net income per limited partner unit |
$ | 1.89 | $ | 42 | ||
| Diluted net income per limited partner unit |
$ | 1.88 | $ | 42 | ||
The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed of V-1 as of the date of acquisition:
| Current assets |
$ | 4,952 | ||
| Property, plant, & equipment |
29,324 | |||
| Goodwill |
20 | |||
| Customer lists (15 years) |
740 | |||
| Trademarks |
370 | |||
| Total assets acquired |
$ | 35,406 | ||
| Total liabilities assumed |
(423 | ) | ||
| Net assets acquired |
$ | 34,983 | ||
Of the total amount assigned to goodwill, $20 is expected to be deductible for tax purposes.
During the year ended August 31, 2003, Heritage also acquired substantially all of the assets of four other companies, which included V-1 Oil Company of Spokane, Washington, Stegall Petroleum located in North Carolina, 1st Propane of Boise Idaho, and Love Propane Gas located in South Carolina. Heritage also purchased the stock of Tri-Cities Gas Company, Inc. located in Alabama. The aggregate purchase price for these acquisitions totaled $6.4 million, which included liabilities assumed and non-compete agreements of $1.4 million for periods ranging from five to ten years. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. These acquisitions were financed primarily with the acquisition facility and were accounted for by the purchase method under SFAS 141. Heritage has historically accounted for business combinations using the purchase method; therefore, the guidelines of SFAS 141 did not have a significant impact on how Heritage accounted for these acquisitions.
During the year ended August 31, 2002, Heritage purchased the stock of Virginia Gas Propane Company, Inc., in Virginia, Mt. Pleasant Propane, Inc. in Tennessee and two other smaller companies. Heritage also acquired substantially all of the assets of six companies, which included Tri-County Propane, Inc., located in North Carolina, Franconia Gas Corporation located in New Hampshire and Quality Gas, Inc. also located in North Carolina. The aggregate purchase price for these acquisitions totaled $24,915, which included liabilities assumed and non-compete agreements of $5.2 million for periods ranging from five to ten years. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. These acquisitions were financed primarily with the acquisition facility and were accounted for by the purchase method under SFAS 141.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Heritage recorded the following intangible assets in conjunction with these acquisitions as of August 31, 2003:
| Customer lists (15 years) |
$ | 1,166 | |
| Non-compete agreements (5 to 10 years) |
769 | ||
| Total amortized intangible assets |
1,935 | ||
| Trademarks and trade names |
381 | ||
| Goodwill |
860 | ||
| Other assets |
— | ||
| Total intangible assets acquired |
$ | 3,176 | |
Goodwill was warranted because these acquisitions enhance Heritage’s current operations and certain acquisitions are expected to reduce costs through synergies with existing operations. Heritage assigned all of the goodwill acquired to the retail-operating segment of Heritage. The results of operations from these acquisitions are included on Heritage’s statement of operations from the dates acquired.
4. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:
Long-term debt consists of the following:
| August 31, 2003 |
||||
| 1996 8.55% Senior Secured Notes |
$ | 96,000 | ||
| 1997 Medium Term Note Program: |
||||
| 7.17% Series A Senior Secured Notes |
12,000 | |||
| 7.26% Series B Senior Secured Notes |
20,000 | |||
| 6.50% Series C Senior Secured Notes |
2,143 | |||
| 2000 and 2001 Senior Secured Promissory Notes: |
||||
| 8.47% Series A Senior Secured Notes |
16,000 | |||
| 8.55% Series B Senior Secured Notes |
32,000 | |||
| 8.59% Series C Senior Secured Notes |
27,000 | |||
| 8.67% Series D Senior Secured Notes |
58,000 | |||
| 8.75% Series E Senior Secured Notes |
7,000 | |||
| 8.87% Series F Senior Secured Notes |
40,000 | |||
| 7.21% Series G Senior Secured Notes |
19,000 | |||
| 7.89% Series H Senior Secured Notes |
8,000 | |||
| 7.99% Series I Senior Secured Notes |
16,000 | |||
| Senior Revolving Acquisition Facility |
24,700 | |||
| Notes payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010, collateralized by a first security lien on certain assets of Heritage |
20,110 | |||
| Other |
1,118 | |||
| Current maturities of long-term debt |
(38,309 | ) | ||
| $ | 360,762 | |||
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Maturities of the Senior Secured Notes, the Medium Term Note Program and the Senior Secured Promissory Notes are as follows:
| 1996 8.55% Senior Secured Notes: | ||
| mature at the rate of $12,000 on June 30 in each of the years 2002 to and including 2011. Interest is paid semi-annually. | ||
| 1997 Medium Term Note Program: | ||
| Series A Notes: |
mature at the rate of $2,400 on November 19 in each of the years 2005 to and including 2009. Interest is paid semi-annually. | |
| Series B Notes: |
mature at the rate of $2,000 on November 19 in each of the years 2003 to and including 2012. Interest is paid semi-annually. | |
| Series C Notes: |
mature at the rate of $714 on March 13 in each of the years 2000 to and including 2003, $357 on March 13, 2004, $1,073 on March 13, 2005, and $357 in each of the years 2006 and 2007. Interest is paid semi-annually. | |
| 2000 and 2001 Senior Secured Promissory Notes: | ||
| Series A Notes: |
mature at the rate of $3,200 on August 15 in each of the years 2003 to and including 2007. Interest is paid quarterly. | |
| Series B Notes: |
mature at the rate of $4,571 on August 15 in each of the years 2004 to and including 2010. Interest is paid quarterly. | |
| Series C Notes: |
mature at the rate of $5,750 on August 15 in each of the years 2006 to and including 2007, $4,000 on August 15, 2008 and $5,750 on August 15, 2009 to and including 2010. Interest is paid quarterly. | |
| Series D Notes: |
mature at the rate of $12,450 on August 15 in each of the years 2008 and 2009, $7,700 on August 15, 2010, $12,450 on August 15, 2011 and $12,950 on August 15, 2012. Interest is paid quarterly. | |
| Series E Notes: |
mature at the rate of $1,000 on August 15 in each of the years 2009 to and including 2015. Interest is paid quarterly. | |
| Series F Notes: |
mature at the rate of $3,636 on August 15 in each of the years 2010 to and including 2020. Interest is paid quarterly. | |
| Series G Notes: |
mature at the rate of $3,800 on May 15 in each of the years 2004 to and including 2008. Interest is paid quarterly. $7.5 million of these notes were retired during the fiscal year ended August 31, 2003. | |
| Series H Notes: |
mature at the rate of $727 on May 15 in each of the years 2006 to and including 2016. Interest is paid quarterly. $19.5 million of these notes were retired during the fiscal year ended August 31, 2003. | |
| Series I Notes: |
mature in one payment of $16,000 on May 15, 2013. Interest is paid quarterly. | |
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
The Senior Secured Notes, the Medium Term Note Program, and the Senior Secured Promissory Notes contain restrictive covenants including limitations on substantial disposition of assets, changes in ownership of Heritage, additional indebtedness, and require the maintenance of certain financial ratios. At August 31, 2003, Heritage was in compliance with these covenants or had no continuing defaults. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of Heritage’s subsidiaries secure the notes.
The Note Agreements for each of the Senior Secured Notes, Medium Term Note Program and Senior Secured Promissory Notes, and the Bank Credit Facility contain customary restrictive covenants applicable to the Operating Partnership, including limitations on the level of additional indebtedness, creation of liens, and sale of assets. These covenants require the Operating Partnership to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the Bank Credit Facility and the Note Agreements) of not more than 5.00 to 1 for the Bank Credit Facility and not more than 5.25 to 1 for the Note Agreements and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the Bank Credit Facility and the Note Agreements) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the Bank Credit Facility and the Note Agreements, Consolidated EBITDA is based upon Heritage’s EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnership may declare, make, or incur a liability to make, a restricted payment during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; and (b) no default or event of default exists before such restricted payment and after giving effect thereto. The debt agreements further provide that Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes. In addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, Available Cash is required to reflect a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
Failure to comply with the various restrictive and affirmative covenants of the Operating Partnership’s Bank Credit Facility and the Note Agreements could negatively impact the Operating Partnership’s ability to incur additional debt and/or Heritage’s ability to pay distributions. The Operating Partnership is required to measure these financial tests and covenants quarterly and was in compliance or had no continuing defaults with all requirements, tests, limitations, and covenants related to the Senior Secured Notes, Medium Term Note Program and Senior Secured Promissory Notes, and the Bank Credit Facility at August 31, 2003.
Effective July 16, 2001, Heritage entered into the Fifth Amendment to the First Amended and Restated Credit Agreement (Bank Credit Facility). The terms of the Bank Credit Facility as amended are as follows:
A $65,000 Senior Revolving Working Capital Facility, expiring June 30, 2004 with $26,700 outstanding at August 31, 2003. The interest rate and interest payment dates vary depending on the terms Heritage agrees to when the money is borrowed. Heritage must be free of all working capital borrowings for 30 consecutive days each fiscal year. The weighted average interest rate was 2.49125% for the amount outstanding at August 31, 2003. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of Heritage’s subsidiaries secure the Senior Revolving Working Capital Facility.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
A $50,000 Senior Revolving Acquisition Facility is available through December 31, 2003, at which time the outstanding amount must be paid in ten equal quarterly installments beginning March 31, 2004, with $24,700 outstanding as of August 31, 2003. The interest rate and interest payment dates vary depending on the terms Heritage agrees to when the money is borrowed. The weighted average interest rate was 2.49125% for the amount outstanding at August 31, 2003. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of Heritage’s subsidiaries secure the Senior Revolving Acquisition Facility.
Heritage entered into an amendment and restatement of the above described Bank Credit Facility effective as of December 31, 2003, which increased the amount available to be borrowed under each of the Working Capital Facility and the Acquisition Facility to up to $75 million and extended the maturity of each Facility to December 31, 2006.
Future maturities of long-term debt for each of the next five fiscal years and thereafter are $38,309 in 2004; $40,288 in 2005; $48,474 in 2006; $38,514 in 2007; $45,223 in 2008, and $188,263 thereafter.
5. COMMITMENTS AND CONTINGENCIES:
Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these leases totaled approximately $1,269, $2,997, and $2,977 for the period ended January 19, 2004 and the years ended August 31, 2003, and 2002, respectively, and has been included in operating expenses in the accompanying statements of operations. Certain of these leases contain renewal options and also contain escalation clauses, which are accounted for on a straight-line basis over the minimum lease term. Fiscal year future minimum lease commitments for such leases are $1,647 in 2004; $1,906 in 2005; $1,325 in 2006; $929 in 2007; $934 in 2008 and $846 thereafter.
The General Partner of Heritage had employment agreements with seven employees. The employment agreements provided for total annual base salary of $1,545. The employment agreements provided for the Executives to participate in bonus and incentive plans.
The Employment Agreements provided that in the event of a change of control of the ownership of the General Partner or in the event an Executive (i) is involuntarily terminated (other than for “misconduct” or “disability”) or (ii) voluntarily terminates employment for “good reason” (as defined in the agreements), such Executive will be entitled to continue receiving his base salary and to participate in all group health insurance plans and programs that may be offered to executives of the General Partner for the remainder of the term of the Employment Agreement or, if earlier, the Executive’s death, and the Executive will vest immediately in the Minimum Award of the number of Common Units to which the Executive is entitled under the Long Term Incentive Plan to the extent not previously awarded, and if the Executive is terminated as a result of the foregoing, all restrictions on the transferability of the units purchased by such executive under the Subscription Agreement dated as of June 15, 2000, shall automatically lapse in full on such date. Pursuant to the Energy Transfer Transactions, the “change of control” provisions of the Employment Agreements were triggered upon consummation of the acquisition by La Grange Energy of Heritage’s General Partner, which resulted in the payment of approximately $1.6 million in salary and the issuance of 150,018 Common Units pursuant to their terms. In addition, pursuant to the terms of one of the Employment Agreements, an additional 20,000 Common Units were issued to a former officer following his retirement subsequent to January 19, 2004. Each Employment
F-227
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Agreement also provided that if any payment received by an Executive is subject to the 20% federal excise tax under Section 4999(a) of the Code of the Internal Revenue Service, the payment will be grossed up to permit the Executive to retain a net amount on an after-tax basis equal to what he would have received had the excise tax and all other federal and state taxes on such additional amount not been payable. In addition, each Employment Agreement contained non-competition and confidentiality provisions.
Heritage is a party to various legal proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against Heritage. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of Heritage. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, Heritage accrues the related deductible. As of August 31, 2003, an accrual of $941 was recorded as accrued and other current liabilities on Heritage’s consolidated balance sheet.
Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which Heritage presently has, or formerly had, operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, Heritage obtained indemnification for expenses associated with any remediation from the former owners or related entities. Heritage has not been named as a potentially responsible party at any of these sites, nor has Heritage’s operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in Heritage’s August 31, 2003 consolidated balance sheet. Based on information currently available to Heritage, such projects are not expected to have a material adverse effect on Heritage’s financial condition or results of operations.
In July 2001, Heritage acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by Heritage was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called “Superfund”). Based upon information currently available to Heritage, it is not believed that Heritage’s liability if such action were to be taken by the EPA would have a material adverse effect on Heritage’s financial condition or results of operations.
6. PARTNERS’ CAPITAL:
The Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (“Partnership Agreement”) contains specific provisions for the allocation of net earnings and losses to each of the partners for purposes of maintaining the partner capital accounts.
On September 1, 2003 and October 25, 2003, an additional 1,500 and 13,300 Common Units, respectively, were issued by Heritage to holders of grants that had previously been awarded under the terms of the Partnership’s Restricted Unit Plan.
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
On December 24, 2003 Heritage issued 413,180 Common Units, with a total value of $13,635 in exchange for certain assets acquired in connection with the acquisition of the remaining 50% of Bi State Propane that Heritage did not previously own, and on January 1, 2004 Heritage issued 92,646 Common Unit with a total value of $3,481 in exchange for certain assets acquired in connection with the acquisition of Metro Lift Propane.
On September 1, 2002 and April 14, 2003, an additional 500 and 2,000 Common Units, respectively, were issued by Heritage to holders of grants that had previously been awarded under the terms of the Partnership’s Restricted Unit Plan. On August 10, 2003, Heritage issued 66,118 Common Units under the terms of Heritage’s Long-Term Incentive Plan upon the attainment of the performance targets required for such awards.
On January 2, 2003, the Heritage issued 551,456 Common Units, with a total value of $15,000 in exchange for certain assets acquired in connection with the acquisition of the propane distribution assets of V-1 Oil Co.
On May 20, 2003, Heritage sold 1,610,000 Common Units in an underwritten public offering at a public offering price of $29.26 per unit. This sale included the exercise of the underwriters’ over-allotment option to purchase an additional 210,000 Common Units. Heritage used approximately $35.9 million of the $44.5 million net proceeds from the sale of the Common Units to repay a portion of the indebtedness outstanding under various tranches of its Senior Secured Notes. The remainder of the proceeds was used for general partnership purposes, including repayment of additional debt. To effect the transfer of the contribution required by the General Partner to maintain its 1% general partner interest in Heritage and its 1.0101% general partner interest in the Operating Partnership as a result of the offering, the General Partner contributed 32,692 previously issued Common Units back to Heritage and those units were cancelled.
Prior to February 4, 2002, Heritage had Class B Subordinated Units representing limited partner interests that were issued to certain former stockholders of Heritage Holdings, who are or were also members of management, in connection with the transaction with U.S. Propane. The Class B Subordinated Units had the same voting rights as the Subordinated Units outstanding before the end of the Subordination Period, and generally participated pro rata with the Common Units in Heritage’s income, gains, losses, deductions, credits, and distributions. Each Class B Subordinated Unit was entitled to one vote on each matter with respect to which the Class B Subordinated Units were entitled to vote.
On February 4, 2002, at a special meeting of the Common Unitholders of the Registrant, the Common Unitholders approved the amendment of the Partnership Agreement that converted all of the 1,382,514 outstanding Class B Subordinated Units into 1,382,514 Common Units. The Common Units issued upon conversion of the Class B Subordinated Units share equally with other Common Units in distributions of Available Cash.
In conjunction with the Common Unitholder approval of the substitution of U.S. Propane as the General Partner of Heritage, Heritage issued 162,913 Common Units to the former General Partner Heritage Holdings in exchange for its 1.0101% general partner interest in the Operating Partnership. Heritage also issued 158,026 Common Units to Heritage Holdings in conversion of its 1% general partner interest in Heritage and cancelled 158,026 Common Units held by U.S. Propane upon their conversion into Incentive Distribution Rights and a 1% general partner interest in Heritage and 1,646 Common Units held by U.S. Propane to maintain its general partner interest in Heritage.
On September 1, 2001 and June 30, 2002, an additional 1,750 and 10,000 Common Units, respectively, were issued by Heritage to holders of grants that had previously been awarded under the terms of Heritage’s Restricted Unit Plan.
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Index to Financial Statements
HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
In conjunction with the transaction with U.S. Propane and the change of control of the former General Partner, Heritage Holdings, Heritage issued 1,000,000 newly created Class C Units to Heritage Holdings in conversion of that portion of its Incentive Distribution Rights that entitled it to receive any distribution made by Heritage attributable to the net amount received in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation filed by Heritage prior to the transaction with U.S. Propane. The Class C Units have zero initial capital account balance and were distributed by Heritage Holdings to its former stockholders in connection with the transaction with U.S. Propane. Thus, U.S. Propane will not receive any distributions made with respect to the SCANA litigation that would have gone to Heritage Holdings with respect to its General Partner interest and Incentive Distribution Rights had it remained the General Partner of Heritage. Upon receiving final cash payment as a result of the resolution of the SCANA litigation, the special litigation committee will determine the amount of litigation proceeds to be distributed, after deducting all costs and expenses of the litigation incurred by Heritage and its affiliates and such reserves as the special committee deems necessary or advisable. The resulting amount of distributable proceeds will be distributed in the same manner as Heritage’s distribution of “Available Cash” pursuant to the Partnership Agreement, except that the amount that would normally be distributed to the holders of Incentive Distribution Rights will be distributed to the holders of Class C Units, pro rata. Each holder of Class C Units receiving a distribution of cash in any taxable year will be allocated items of gross income with respect to such taxable year in an amount equal to the cash distributed to the holder. Holders of Class C Units will not be allocated any other items of income, gain, loss deduction or credit and have no other rights except the right to share in any distributions upon dissolution and liquidation of the Partnership if such distributions consist of proceeds from the SCANA litigation and to which the Class C Units would have otherwise been entitled. The Class C Units may not be converted into any other unit. The Class C Units have no voting rights, except to the extent provided by Delaware law with respect to a vote as a class, in which case each Class C Unit will be entitled to one vote.
Quarterly Distributions of Available Cash
The Partnership Agreement requires that Heritage will distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of Heritage, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of Heritage’s business, to comply with applicable laws or any Heritage debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in the Partnership Agreement.
Prior to the Unitholder vote on February 4, 2002, distributions by Heritage in an amount equal to 100% of Available Cash were made 97% to the common and Class B Subordinated Unitholders, 1.0101% to U.S. Propane for its limited partner interest in the Operating Partnership and 1.9899% to the former General Partner, Heritage Holdings. After the Unitholder vote, distributions by Heritage in an amount equal to 100% of Available Cash will generally be made 98% to the Common Unitholders and 2% to U.S. Propane, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved.
The Minimum Quarterly Distribution was made to the Common and Subordinated Unitholders for the quarters ended November 30, 1996 through August 31, 1998. For the quarter ended November 30, 1998, a quarterly distribution of $0.5125 was paid to the Common and Subordinated Unitholders. For each of the
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
quarters ended February 28, 1999 through and including May 31, 2000, quarterly distributions of $0.5625 per unit were paid to the Common and Subordinated Unitholders. Heritage raised the quarterly distribution $0.0125 per unit for each of the six consecutive quarters beginning with the quarter ended August 31, 2000 through the quarter ended November 30, 2001. The distribution remained at $0.6375 per unit for each of the quarters ended February 28, 2002 through and including May 31, 2003. For each of the quarters ended August 31, 2003, through and including November 30, 2003, quarterly distributions of $0.65 per unit (or $2.60 annually) were paid to the Common Unitholders. The quarterly distributions for the quarters ended February 28, 1999 through November 30, 2003 included incentive distributions payable to the General Partner to the extent the quarterly distribution exceeded $0.55 per unit.
After the conversion of the Class B Subordinated Units was approved on February 4, 2002, each Class B Subordinated unit converted into one Common Unit and then participates pro rata with the other Common Units in distributions of Available Cash. Heritage currently distributes Available Cash, excluding any Available Cash to be distributed to the Class C Unitholders as follows:
| • | First, 98% to all Unitholders, pro rata, and 2% to the General Partner, until all Unitholders have received $0.50 per unit for such quarter and any prior quarter; |
| • | Second, 98% to all Unitholders, pro rata, and 2% to the General Partner, until all Unitholders have received $0.55 per unit for such quarter; |
| • | Third, 85% to all Unitholders, pro rata, 13% to the holders of Incentive Distribution Right, pro rata, and 2% to the General Partner, until all Common Unitholders have received at least $0.635 per unit for such quarter; |
| • | Fourth, 75% to all Unitholders, pro rata, 23% to the holders of Incentive Distribution Right, pro rata and 2% to the General Partner, until all Common Unitholders have received at least $0.825 per unit for such quarter; |
| • | Fifth, thereafter 50% to all Unitholders, pro rata, 48% to the holders of Incentive Distribution Right, pro rata, and 2% to the General Partner. |
The total amount of distributions paid during the period ended January 19, 2004 on Common Units, the general partner interests and the Incentive Distribution Rights totaled $12.0 million, $0.3 million and $0.3 million, respectively. All such distributions were made from Available Cash from Operating Surplus.
Restricted Unit Plan
The General Partner of Heritage has adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan (the “Restricted Unit Plan”), for certain directors and key employees of the General Partner and its affiliates. The Restricted Unit Plan covers rights to acquire 146,000 Common Units. The right to acquire the Common Units under the Restricted Unit Plan, including any forfeiture or lapse of rights is available for grant to key employees on such terms and conditions (including vesting conditions) as the Compensation Committee of the General Partner shall determine. Each director shall automatically receive a Director’s grant with respect to 500 Common Units on each September 1 that such person continues as a director. Newly elected directors are also entitled to receive a grant with respect to 2,000 Common Units upon election or appointment to the Board. Directors who are employees of U.S. Propane, TECO, Atmos Energy, Piedmont Natural Gas or AGL Resources or their affiliates are not entitled to receive a Director’s grant of Common Units. Generally, the rights to acquire the
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
Common Units will vest upon the later to occur of the three-year anniversary of the grant date, or on such terms as the Compensation Committee may establish, which may include the achievement of performance objectives. In the event of a “change of control” (as defined in the Restricted Unit Plan), all rights to acquire Common Units pursuant to the Restricted Unit Plan will immediately vest. Pursuant to the Energy Transfer Transactions, the change of control provisions of the Restricted Unit Plan were triggered, resulting in the early vesting of 21,600 units by Heritage. Individuals holding 4,500 grants waived their rights to early vesting under the change of control provisions.
The issuance of the Common Units pursuant to the Restricted Unit Plan is intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of the Common Units. Therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units. As of January 19, 2004, 4,500 restricted units were outstanding and 14,300 were available for grants to non-employee directors and key employees. Deferred compensation expense of $668, $244 and $378 was recognized for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively.
Long-Term Incentive Plan
Effective September 1, 2000, Heritage adopted a long-term incentive plan whereby Common Units were to be awarded based on achieving certain targeted levels of Distributed Cash (as defined in the Long Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years’ Distributed Cash per unit. A minimum of 250,000 Common Units and if certain targeted levels were achieved, a maximum of 500,000 Common Units could be awarded. In connection with the January 2004 acquisition of our general partner by La Grange Energy, L.P., the minimum award, reduced by the amount of previous awards and any amounts not awarded, vested, and a total of 150,018 Common Units were issued.
Deferred compensation expense of $564, $915 and $1,500 was recognized for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively.
7. PROFIT SHARING AND 401(K) SAVINGS PLAN:
Heritage sponsors a defined contribution profit sharing and 401(k) savings plan (the “Plan”), which covers all employees subject to service period requirements. Contributions are made to the Plan at the discretion of the Board of Directors and are allocated to eligible employees as of the last day of the plan year based on their pro rata share of total contributions. Employer matching contributions are calculated using a discretionary formula based on employee contributions. Heritage did not recognize any expense under the profit sharing provision of the Plan for the period ended January 19, 2004 or during the years ended August 31, 2003 or 2002. Heritage made matching contributions of $956, $2,144, and $2,339 to the 401(k) savings plan for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively.
8. RELATED PARTY TRANSACTIONS:
Heritage has no employees and is managed by the General Partner. Pursuant to the Partnership Agreement, the General Partner is entitled to reimbursement for all direct and indirect expenses incurred or payments it makes on behalf of Heritage, and all other necessary or appropriate expenses allocable to Heritage or otherwise reasonably incurred by the General Partner in connection with operating Heritage’s business. These costs, which
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
totaled approximately $47,380 for the period ended January 19, 2004, $108,861 for the year ended August 31, 2003, and $95,749 for the year ended August 31, 2002, include compensation and benefits paid to officers and employees of the General Partner.
Accounts payable to related companies include non-interest bearing amounts payable from Heritage to the General Partner of $4,784 as of August 31, 2003 and interest bearing amounts payable of $1,471 to Bi-State Propane as of August 31, 2003. Bi-State Propane purchases all of Bi-State’s propane that is delivered to and sold out of its plants from an affiliate of Bi-State under a supply agreement. The supply agreement requires the affiliate to sell propane to Bi-State at the affiliates established cost plus freight charges to the destination. Total purchases under the agreement by Bi-State were 5.9 million gallons, 17.0 million gallons and 12.8 million gallons for a total cost of $4,359, $11,975, and $7,480, for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively.
9. REPORTABLE SEGMENTS:
Heritage’s financial statements reflect four reportable segments: the domestic retail operations of Heritage, the domestic wholesale operations of Heritage, the foreign wholesale operations of MP Energy Partnership, and the liquids marketing activities of Resources. Heritage’s reportable domestic and wholesale fuel segments are strategic business units that sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. Heritage manages these segments separately as each segment involves different distribution, sale, and marketing strategies. Heritage evaluates the performance of its operating segments based on operating income, exclusive of selling, general, and administrative expenses of $10,100, $14,037 and $12,978 for the period ended January 19, 2004 and the years ended August 31, 2003 and 2002, respectively. Selling, general and administrative expenses, interest expense and other expenses are not allocated by segment. Investment in affiliates and equity in earnings (losses) of affiliates relates primarily to Heritage’s investment in Bi-State Propane (see Note 10), and is part of the domestic retail fuel segment. The following table presents the unaudited financial information by segment for the following periods:
| For the Period ended January 19, 2004 |
For the Years ended August 31, |
||||||||
| 2003 |
2002 |
||||||||
| Gallons: |
|||||||||
| Domestic retail propane |
171,653 | 375,939 | 329,574 | ||||||
| Domestic wholesale propane |
5,381 | 15,343 | 16,798 | ||||||
| Foreign wholesale propane |
|||||||||
| Affiliated |
45,386 | 94,881 | 67,265 | ||||||
| Unaffiliated |
23,299 | 58,958 | 65,309 | ||||||
| Elimination |
(45,386 | ) | (94,881 | ) | (67,265 | ) | |||
| Total |
200,333 | 450,240 | 411,681 | ||||||
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
| For the Period ended January 19, 2004 |
For the Years ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| Revenues: |
||||||||||||
| Domestic retail propane |
$ | 221,459 | $ | 463,392 | $ | 365,334 | ||||||
| Domestic wholesale propane |
4,036 | 10,719 | 9,956 | |||||||||
| Foreign wholesale propane |
||||||||||||
| Affiliated |
45,209 | 59,126 | 33,561 | |||||||||
| Unaffiliated |
16,560 | 36,647 | 31,248 | |||||||||
| Elimination |
(45,209 | ) | (59,126 | ) | (33,561 | ) | ||||||
| Liquids marketing, net |
369 | 1,333 | 542 | |||||||||
| Other |
27,928 | 59,385 | 55,245 | |||||||||
| Total |
$ | 270,352 | $ | 571,476 | $ | 462,325 | ||||||
| Operating Income (Loss): |
||||||||||||
| Domestic retail propane |
$ | 44,972 | $ | 83,945 | $ | 55,901 | ||||||
| Domestic wholesale propane |
(726 | ) | (2,903 | ) | (3,940 | ) | ||||||
| Foreign wholesale propane |
||||||||||||
| Affiliated |
483 | 784 | 500 | |||||||||
| Unaffiliated |
1,614 | 2,608 | 1,914 | |||||||||
| Elimination |
(483 | ) | (784 | ) | (500 | ) | ||||||
| Liquids marketing |
39 | 580 | 64 | |||||||||
| Selling, general and administrative not allocated to segments |
(10,100 | ) | (14,037 | ) | (12,978 | ) | ||||||
| Total |
$ | 35,799 | $ | 70,193 | $ | 40,961 | ||||||
| For the Period ended January 19, 2004 |
For the Years ended August 31, |
|||||||||||
| 2003 |
2002 |
|||||||||||
| Gain (Loss) on Disposal of Assets: |
||||||||||||
| Domestic retail propane |
$ | (251 | ) | $ | 386 | $ | 544 | |||||
| Domestic wholesale propane |
11 | 44 | 268 | |||||||||
| Total |
$ | (240 | ) | $ | 430 | $ | 812 | |||||
| Minority Interest Expense: |
||||||||||||
| Corporate |
$ | 231 | $ | 318 | $ | 213 | ||||||
| Foreign wholesale propane |
341 | 558 | 361 | |||||||||
| Total |
$ | 572 | $ | 876 | $ | 574 | ||||||
| Depreciation and amortization: |
||||||||||||
| Domestic retail propane |
$ | 15,195 | $ | 37,442 | $ | 36,550 | ||||||
| Domestic wholesale propane |
184 | 494 | 426 | |||||||||
| Foreign wholesale propane |
10 | 23 | 22 | |||||||||
| Total |
$ | 15,389 | $ | 37,959 | $ | 36,998 | ||||||
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
| As of August 31, 2003 | |||
| Total Assets: |
|||
| Domestic retail propane |
$ | 691,900 | |
| Domestic wholesale propane |
12,197 | ||
| Foreign wholesale propane |
13,912 | ||
| Liquids marketing |
4,474 | ||
| Corporate |
16,356 | ||
| Total |
$ | 738,839 | |
| Additions to property, plant and equipment including acquisitions: |
|||
| Domestic retail propane |
$ | 57,499 | |
| Domestic wholesale propane |
280 | ||
| Foreign wholesale propane |
— | ||
| Corporate |
2,344 | ||
| Total |
$ | 60,123 | |
Corporate assets include vehicles, office equipment and computer software for the use of administrative personnel. These assets are not allocated to segments. Corporate minority interest expense relates to U.S. Propane’s general partner interest in the Operating Partnership.
9. SIGNIFICANT INVESTEE:
At August 31, 2003, Heritage held a 50% interest in Bi-State Propane. Heritage accounted for this 50% interest in Bi-State Propane under the equity method. Heritage’s investment in Bi-State Propane totaled $8,242 at August 31, 2003. Heritage received distributions of $535 from Bi-State Propane for the year ended August 31, 2003. The Operating Partnership guaranteed $5 million of debt incurred by Bi-State Propane to a financial institution. At August 31, 2003, management considered the likelihood of Heritage incurring a liability resulting from the guarantee to be remote. Therefore Heritage did not record a liability on the balance sheets as of August 31, 2003 for this guarantee because the guarantee was in effect prior to the issuance of FIN 45, and there have been no amendments to the original guarantee. Bi-State Propane’s financial position is summarized below:
| August 31, 2003 | |||
| Current assets |
$ | 3,393 | |
| Noncurrent assets |
23,187 | ||
| $ | 26,580 | ||
| Current liabilities |
$ | 3,701 | |
| Long-term debt |
7,750 | ||
| Partners’ capital: |
|||
| Heritage |
8,242 | ||
| Other partner |
6,887 | ||
| $ | 26,580 | ||
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HERITAGE PROPANE PARTNERS, L.P. AND SUBSIDIARIES
(HERITAGE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands, except unit and per unit data)
On December 24, 2003, Heritage purchased the 50% interest in Bi-State Propane that it did not previously own. Heritage now owns 100% of Bi-State Propane. Beginning December 24, 2003, Heritage consolidates the results of Bi-State, as Bi-State became a wholly owned subsidiary of the Partnership. Bi-State Propane’s results of operations for the years ended August 31, 2003 and 2002, respectively are summarized below:
| For the Years Ended August 31, | ||||||
| 2003 |
2002 | |||||
| Revenues |
$ | 22,536 | $ | 16,815 | ||
| Gross profit |
10,507 | 8,934 | ||||
| Net income: |
||||||
| Heritage |
1,292 | 1,274 | ||||
| Other Partner |
1,275 | 1,329 | ||||
10. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. The sum of net income (loss) per limited partner unit by quarter may not equal the net income (loss) per limited partner unit for the year due to variations in the weighted average units outstanding used in computing such amounts. Heritage’s business is seasonal due to weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive.
| Quarter Ended November 30 |
Period Ended January 19, 2004 | ||||||
| Fiscal 2004: |
|||||||
| Revenues |
$ | 123,726 | $ | 146,626 | |||
| Gross Profit |
57,356 | 64,667 | |||||
| Operating income (loss) |
6,709 | 29,090 | |||||
| Net income (loss) |
(1,296 | ) | 23,939 | ||||
| Basic and diluted net income (loss) per limited partner unit |
$ | (0.09 | ) | $ | 1.30 | ||
| Quarter Ended |
||||||||||||||
| November 30 |
February 28 |
May 31 |
August 31 |
|||||||||||
| Fiscal 2003: |
||||||||||||||
| Revenues |
$ | 113,460 | $ | 249,809 | $ | 125,739 | $ | 82,468 | ||||||
| Gross Profit |
56,440 | 121,389 | 58,958 | 37,533 | ||||||||||
| Operating income (loss) |
10,926 | 62,385 | 6,154 | (9,271 | ) | |||||||||
| Net income (loss) |
1,504 | 49,752 | (2,166 | ) | (17,948 | ) | ||||||||
| Basic and diluted net income (loss) per limited partner unit |
$ | 0.08 | $ | 3.03 | $ | (0.14 | ) | $ | (1.01 | ) | ||||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Bi-State Propane
We have audited the accompanying balance sheet of Bi-State Propane (a California general partnership) as of August 31, 2002 and the related statements of operations, partners’ capital and cash flows for the year then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Bi-State Propane as of August 31, 2002 and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
As explained in Note 2 to the consolidated financial statements, effective September 1, 2001, the Partnership changed its method of accounting for goodwill and other intangible assets to adopt the requirements of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
/s/ Grant Thornton LLP
Tulsa, Oklahoma
October 25, 2002
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BALANCE SHEETS
(in thousands)
| August 31, 2003 |
August 31, 2002 | |||||
| (unaudited) | ||||||
| ASSETS | ||||||
| CURRENT ASSETS: |
||||||
| Cash |
$ | 156 | $ | 134 | ||
| Accounts receivable, net of allowance for doubtful accounts |
948 | 740 | ||||
| Accounts receivable from affiliates |
1,472 | 1,691 | ||||
| Inventories |
763 | 675 | ||||
| Prepaid expenses and other |
54 | 81 | ||||
| Total current assets |
3,393 | 3,321 | ||||
| PROPERTY, PLANT AND EQUIPMENT, net |
14,603 | 14,088 | ||||
| GOODWILL, net of amortization prior to adoption of SFAS No. 142 |
5,116 | 5,116 | ||||
| INTANGIBLES AND OTHER ASSETS, net |
3,468 | 3,901 | ||||
| Total assets |
$ | 26,580 | $ | 26,426 | ||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||
| CURRENT LIABILITIES: |
||||||
| Accounts payable |
1,309 | 1,200 | ||||
| Accrued and other current liabilities |
692 | 444 | ||||
| Current maturities of long-term debt |
1,700 | 1,700 | ||||
| Total current liabilities |
3,701 | 3,344 | ||||
| LONG-TERM DEBT, less current maturities |
7,750 | 9,450 | ||||
| 11,451 | 12,794 | |||||
| COMMITMENTS AND CONTINGENCIES |
||||||
| PARTNERS’ CAPITAL: |
||||||
| Heritage Bi-State, L.L.C. |
8,242 | 7,485 | ||||
| Allied Propane Service, Inc. |
6,887 | 6,147 | ||||
| Total partners’ capital |
15,129 | 13,632 | ||||
| Total liabilities and partners’ capital |
$ | 26,580 | $ | 26,426 | ||
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF OPERATIONS
(in thousands)
| For the Year Ended August 31, |
||||||||
| 2003 |
2002 |
|||||||
| (Unaudited) | ||||||||
| REVENUES: |
||||||||
| Retail fuel |
$ | 20,611 | $ | 15,075 | ||||
| Other |
1,925 | 1,740 | ||||||
| Total revenues |
22,536 | 16,815 | ||||||
| COSTS AND EXPENSES: |
||||||||
| Cost of products sold |
12,030 | 7,881 | ||||||
| Operating expenses |
5,950 | 4,768 | ||||||
| Depreciation and amortization |
1,425 | 1,152 | ||||||
| Selling, general and administrative |
169 | 130 | ||||||
| Total costs and expenses |
19,574 | 13,931 | ||||||
| OPERATING INCOME |
2,962 | 2,884 | ||||||
| OTHER INCOME (EXPENSE): |
||||||||
| Interest expense |
(371 | ) | (324 | ) | ||||
| Interest income from affiliate |
40 | 62 | ||||||
| Other income |
(7 | ) | — | |||||
| Loss on disposal of assets |
(57 | ) | (19 | ) | ||||
| NET INCOME |
$ | 2,567 | $ | 2,603 | ||||
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
| Heritage Bi-State, L.L.C. |
Allied Propane Service, Inc. |
Total |
||||||||||
| Balance, August 31, 2001 |
$ | 6,611 | $ | 5,218 | $ | 11,829 | ||||||
| Distributions to Partners |
(400 | ) | (400 | ) | (800 | ) | ||||||
| Net income |
1,274 | 1,329 | 2,603 | |||||||||
| Balance, August 31, 2002 |
7,485 | 6,147 | 13,632 | |||||||||
| Distributions to Partners (Unaudited) |
(535 | ) | (535 | ) | (1,070 | ) | ||||||
| Net income (Unaudited) |
1,292 | 1,275 | 2,567 | |||||||||
| Balance, August 31, 2003 (Unaudited) |
$ | 8,242 | $ | 6,887 | $ | 15,129 | ||||||
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
(in thousands)
| For the Years Ended August 31, |
||||||||
| 2003 |
2002 |
|||||||
| (Unaudited) | ||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Net income |
$ | 2,567 | $ | 2,603 | ||||
| Reconciliation of net income to net cash provided by operating activities- |
||||||||
| Depreciation and amortization |
1,425 | 1,152 | ||||||
| Provision for loss on accounts receivable |
11 | 21 | ||||||
| Loss on disposal of assets |
57 | 19 | ||||||
| Changes in assets and liabilities, net of effect of acquisitions: |
||||||||
| Accounts receivable |
(219 | ) | 299 | |||||
| Accounts receivable from affiliates |
(316 | ) | (1,084 | ) | ||||
| Inventories |
(88 | ) | 232 | |||||
| Prepaid expenses and other |
27 | 40 | ||||||
| Accounts payable |
109 | 431 | ||||||
| Accrued and other current liabilities |
249 | (248 | ) | |||||
| Net cash provided by operating activities |
3,822 | 3,465 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Cash paid for acquisition, net of cash acquired |
— | (9,739 | ) | |||||
| Capital expenditures |
(1,665 | ) | (755 | ) | ||||
| Proceeds from the sale of assets |
100 | 269 | ||||||
| Net cash used in investing activities |
(1,565 | ) | (10,225 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
| Proceeds from borrowings |
— | 12,000 | ||||||
| Principal payments on debt |
(1,700 | ) | (4,825 | ) | ||||
| Debt issuance costs |
— | (42 | ) | |||||
| Distribution to Partner |
(535 | ) | (400 | ) | ||||
| Net cash provided by (used in) financing activities |
(2,235 | ) | 6,733 | |||||
| INCREASE (DECREASE) IN CASH |
22 | (27 | ) | |||||
| CASH, beginning of period |
134 | 161 | ||||||
| CASH, end of period |
$ | 156 | $ | 134 | ||||
| NONCASH FINANCING ACTIVITY: |
||||||||
| Distribution to Partner |
$ | 535 | $ | 400 | ||||
| NONCASH INVESTING ACTIVITY: |
||||||||
| Working capital payment, net of cash received on acquisition |
$ | — | $ | 640 | ||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
||||||||
| Cash paid during the period for interest |
$ | 317 | $ | 362 | ||||
The accompanying notes are an integral part of these financial statements
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Index to Financial Statements
NOTES TO FINANCIAL STATEMENTS
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
1. OPERATIONS AND ORGANIZATION:
Bi-State Propane (“Bi-State”) is a California general partnership that owns and operates propane businesses in California and Nevada. Bi-State is owned equally by Allied Propane Service, Inc., (“Allied”) and Heritage Bi-State, L.L.C., (“Heritage Bi-State”) (together referred to as the “Partners”). Heritage Bi-State is wholly owned by Heritage Operating L.P., the Operating Partnership of Heritage Propane Partners, L.P. Profits and losses of Bi-State are shared equally by the Partners, with the exception of amortization and depreciation differences due to the basis of the Partners’ initial contributions.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Revenue Recognition
Sales of propane, propane appliances, parts and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor is recognized upon completion of the service, and tank rent is recognized ratably over the period it is earned. Shipping and handling revenues are included in the price of propane charged to customers, and thus are classified as revenues.
Costs and Expenses
Costs of products sold include actual cost of fuel sold, storage fees and inbound freight, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs, purchasing costs, and plant operations. Selling, general and administrative expenses includes the negotiated administrative fee as described in the Administrative Agreement with Heritage Bi-State and Bi-State (see Note 8) for the administrative functions performed by Heritage Bi-State including, but not limited to, accounting, insurance, cash management, training, and employee benefits.
Accounts Receivable
Bi-State grants credit to its customers for the purchase of propane and propane-related products. Accounts receivable are recorded at amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of the Partnership’s customers and any specific disputes. Bi-State recorded bad debt expense net of recoveries of $11 and $21 during the years ended August 31, 2003 and 2002, respectively. Accounts receivable consisted of the following:
| August 31, 2003 |
August 31, 2002 | |||||
| Accounts receivable |
$ | 976 | $ | 768 | ||
| Less—allowance for doubtful accounts |
28 | 28 | ||||
| Total, net |
$ | 948 | $ | 740 | ||
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
The following summarizes the activity in the allowance for doubtful accounts for the following years ended:
| August 31, 2003 |
August 31, 2002 |
|||||||
| Allowance for doubtful accounts: |
||||||||
| Balance, beginning of the year |
$ | 28 | $ | 28 | ||||
| Provision for loss on accounts receivable |
11 | 21 | ||||||
| Accounts receivable written off, net of recoveries |
(11 | ) | (21 | ) | ||||
| Balance, end of period |
$ | 28 | $ | 28 | ||||
Inventories
Inventories are valued at the lower of cost or market. The cost of fuel inventories is determined using weighted-average cost delivered to the retail locations and includes storage fees and inbound freight costs, while the cost of appliances, parts and fittings is determined by the first-in, first-out method. Inventories consisted of the following:
| August 31, 2003 |
August 31, 2002 | |||||
| Fuel |
$ | 549 | $ | 436 | ||
| Appliances, parts and fittings |
214 | 239 | ||||
| $ | 763 | $ | 675 | |||
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish tanks that either extend the useful lives of the tanks or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the tanks. Additionally, Bi-State capitalizes certain costs directly related to the installation of company-owned tanks, including internal labor costs. Components and useful lives of property, plant and equipment were as follows:
| August 31, 2003 |
August 31, 2002 |
|||||||
| Land and improvements |
$ | 1,346 | $ | 1,396 | ||||
| Buildings and improvements (10 to 30 years) |
1,239 | 1,148 | ||||||
| Bulk storage, equipment and facilities (3 to 30 years) |
3,827 | 3,554 | ||||||
| Tanks and other equipment (5 to 30 years) |
8,345 | 8,314 | ||||||
| Vehicles (5 to 10 years) |
3,578 | 3,211 | ||||||
| Furniture and fixtures (5 to 10 years) |
233 | 230 | ||||||
| Other |
153 | 149 | ||||||
| 18,721 | 18,002 | |||||||
| Less—Accumulated depreciation |
(4,758 | ) | (3,978 | ) | ||||
| 13,963 | 14,024 | |||||||
| Plus—Construction work-in-process |
640 | 64 | ||||||
| Property, plant and equipment, net |
$ | 14,603 | $ | 14,088 | ||||
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
Intangibles and Other Assets
Intangibles and other assets are stated at cost, net of amortization computed on the straight-line method. Bi-State eliminates from its balance sheet any fully amortized intangibles and the related accumulated amortization. Components and useful lives of intangibles and other assets were as follows:
| August 31, 2003 |
August 31, 2002 |
|||||||||||||
| Gross Carrying Amount |
Accumulated Amortization |
Gross Carrying Amount |
Accumulated Amortization |
|||||||||||
| Amortized intangible assets |
||||||||||||||
| Customer lists (15 years) |
$ | 3,402 | $ | (1,200 | ) | $ | 3,402 | $ | (973 | ) | ||||
| Noncompetes (5 to 10 years) |
1,857 | (631 | ) | 1,857 | (431 | ) | ||||||||
| Financing costs (5 years) |
42 | (8 | ) | 42 | (3 | ) | ||||||||
| Total |
5,301 | (1,839 | ) | 5,301 | (1,407 | ) | ||||||||
| Unamortized intangible assets |
||||||||||||||
| Other assets |
6 | — | 7 | — | ||||||||||
| Total intangibles and other |
$ | 5,307 | $ | (1,839 | ) | $ | 5,308 | $ | (1,407 | ) | ||||
Aggregate amortization expense of intangible assets was $432 and $327 for the years ended August 31, 2003 and 2002, respectively. The estimated aggregate amortization expense for the next five fiscal years based on the balances at August 31, 2003 is $427 for 2004; $422 for 2005; $372 for 2006; $372 for 2007 and $372 for 2008.
Goodwill
Goodwill is associated with acquisitions made for Bi-State’s domestic retail operations, which is the only operating segment of Bi-State. Goodwill is tested for impairment at the end of each fiscal year in accordance with SFAS 142. The changes in the carrying amount of goodwill for the years ended August 31, 2002 and 2003 are as follows:
| Balance as of August 31, 2001 |
$ | 1,810 | |
| Goodwill acquired during the year |
3,306 | ||
| Impairment losses |
— | ||
| Goodwill written off to sale of business |
— | ||
| Balance as of August 31, 2002 |
5,116 | ||
| Goodwill acquired during the year |
— | ||
| Impairment losses |
— | ||
| Goodwill written off to sale of business |
— | ||
| Balance as of August 31, 2003 |
$ | 5,116 | |
Long-lived Assets
Bi-State reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, Bi-State reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the years ended August 31, 2003 and 2002.
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
| August 31, 2003 |
August 31, 2002 | |||||
| Interest payable |
$ | 55 | $ | — | ||
| Wages and payroll taxes |
259 | 130 | ||||
| Deferred tank rent |
97 | 97 | ||||
| Customer deposits |
173 | 156 | ||||
| Taxes other than income |
32 | 25 | ||||
| Other |
76 | 36 | ||||
| Accrued and other current liabilities |
$ | 692 | $ | 444 | ||
Income Taxes
As a result of Bi-State’s status as a partnership, earnings or losses for federal and state income tax purposes are included in the tax returns of the individual Partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements of Bi-State for the years ended August 31, 2003 and 2002.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Fair Value
The carrying amounts of trade accounts receivable and trade accounts payable approximate their fair value. An interest bearing receivable/payable account is maintained to monitor the net cash due between Heritage Bi-State and Bi-State. The interest is based on the amount equal to the rate Heritage Operating L.P. pays on its working capital line of credit (2.49125% at August 31, 2003). Based on the estimated borrowing rates currently available to Bi-State for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2003 was $9,744 and $9,450, respectively. The fair value and carrying amount of long-term debt at August 31, 2002 was approximately $11,344 and $11,150, respectively.
SFAS 142 Goodwill and Other Intangible Assets
In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement No. 142, Goodwill and Other Intangible Assets (SFAS 142). Under SFAS 142, goodwill is no longer subject to amortization over its estimated useful life. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value-based test. Additionally, any acquired intangible assets should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so. Those assets will be amortized over their useful lives, other than assets that have an indefinite life.
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
Bi-State adopted SFAS 142 on September 1, 2001 and accordingly has discontinued the amortization of goodwill existing at the time of adoption. Under the provisions of SFAS 142, Bi-State was required to perform a transitional goodwill impairment appraisal within six months from the time of adoption. Management performed an assessment of the fair value of Bi-State’s sole operating segment, which was compared with the carrying value of the segment to determine whether any impairment existed on the date of adoption. Bi-State has completed the transitional goodwill impairment appraisal and has determined that based on the fair value of Bi-State’s operating segment, Bi-State’s goodwill was not impaired as of September 1, 2001. Bi-State has determined that a detailed evaluation of Bi-State’s operating segment as of August 31, 2003 is not necessary based on the fact that there has not been a significant change in the components of Bi-State’s operating segment since the last evaluation, the previous fair value of Bi-State’s operating segment substantially exceeded the carrying value, and the likelihood that Bi-State’s operating segment current carrying value exceeds its current fair value is remote based on an analysis of events and circumstances since Bi-State’s most recent evaluation. Accordingly, no impairment of Bi-State’s goodwill was recorded for the year ended August 31, 2003. Bi-State will continue to test goodwill for impairment as of the end of each fiscal year. The adoption of SFAS 142 eliminated goodwill amortization that would have totaled approximately $133 for the years ended August 31, 2003 and 2002, based on the balances of August 31, 2001.
The following table reflects the effect of the adoption of SFAS 142 on net income as if SFAS 142 had been in effect for all of the periods presented:
| Year Ended August 31, 2003 |
Year Ended August 31, 2002 | |||||
| Net income as reported |
$ | 2,567 | $ | 2,603 | ||
| Add back: goodwill amortization |
— | — | ||||
| Adjusted net income |
$ | 2,567 | $ | 2,603 | ||
Recently Issued Accounting Standards
In June 2002, the FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS 146). SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. Bi-State adopted the provisions of SFAS 146 effective for exit or disposal activities that are initiated after December 31, 2002. The adoption did not have a material impact on the Bi-State’s consolidated financial position or results of operations.
In November 2002, the FASB issued Financial Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 expands the existing disclosure requirements for guarantees and requires that companies recognize a liability for guarantees issued after December 31, 2002. The implementation of FIN 45 did not have a significant impact on Bi-State’s financial position or results of operations.
In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
for hedging relationships designated after June 30, 2003. Bi-State adopted SFAS 149 as of July 1, 2003. The adoption of SFAS 149 did not have a material impact on Bi-State’s consolidated financial position or results of operations.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS 150 as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. Bi-State adopted the provisions of SFAS 150 as of September 1, 2003. The adoption did not have a material impact on the Bi-State’s consolidated financial position or results of operations.
3. ACQUISITIONS:
On March 1, 2002, Bi-State purchased certain assets of the ProFlame acquisition completed by Heritage Propane Partners, L.P. in July 2001. The aggregate purchase price was approximately $9,730 plus working capital. This purchase was made pursuant to the provision in the Bi-State Propane Partnership Agreement that requires each Partner to offer to sell any newly acquired businesses within Bi-State’s area of operations to Bi-State. This acquisition was financed with the Term Note (see Note 4) and was recorded at the same basis as Heritage Propane Partners, L.P. had in those assets, which approximated fair value. Goodwill was warranted in this transaction as the operations of these ProFlame assets enhanced Bi-State’s operations in the Nevada area and is expected to reduce costs through synergies with existing operations.
The following table summarizes the fair value of the assets acquired and liabilities assumed at the date of acquisition:
| Current assets, net of cash acquired |
$ | 648 | |
| Property, plant and equipment |
4,501 | ||
| Goodwill |
3,306 | ||
| Other intangible assets |
1,932 | ||
| Total assets acquired |
10,387 | ||
| Current liabilities |
8 | ||
| Long-term debt |
— | ||
| Total liabilities assumed |
8 | ||
| Net assets acquired |
$ | 10,379 | |
Of the $1,932 of acquired intangible assets, $1,307 was assigned to non-competes, which are being amortized over a 10 year weighted-average useful life and $625 was assigned to customer lists, which are being amortized over a 15 year weighted average useful life.
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
The results of operations of the ProFlame assets are included in the statement of operations of Bi-State for the year ended August 31, 2003 and from March 1, 2002 for the year ended August 31, 2002. The following unaudited pro forma results of operations are presented as if the acquisition of the ProFlame assets had been made at the beginning of the period presented:
| Year Ended August 31, 2002 | |||
| Total revenues |
$ | 20,056 | |
| Net income |
$ | 2,915 | |
The pro forma consolidated results of operations include adjustments to give effect to amortization of non-competes and customer lists, and interest expense on the Term Note. The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the period presented or the future results of the combined operations.
4. LONG-TERM DEBT:
Long-term debt consists of the following:
| August 31, 2003 |
August 31, 2002 | |||||
| Term Note |
$ | 9,450 | $ | 11,150 | ||
| Current maturities |
1,700 | 1,700 | ||||
| Total long-term debt, net of current maturities |
$ | 7,750 | $ | 9,450 | ||
Bi-State entered into the Second Amended and Restated Credit Agreement (the “Credit Agreement”) dated as of February 28, 2002 in connection with the acquisition of certain ProFlame assets. The terms of the Credit Agreement as amended are as follows:
A Term Note in the principal amount of $12,000 payable in quarterly installments of principal in the amount of $425, together with interest with all unpaid interest and principal due at final maturity on February 28, 2007. Interest is payable at the Applicable Rate determined pursuant to the Credit Agreement. Applicable Rate means applicability of the Eurodollar (LIBOR) Rate, the Base Rate of the Fixed Rate, on a per annum basis. With respect to the Eurodollar Rate or any Base Rate, the rate of interest per annum shall be 2.01% plus the Eurodollar Rate if one or the Eurodollar Pricing Options is selected, 0.00% plus the Base Rate if the Base Rate Pricing Option is selected, and 2.10% plus the bank’s cost of funds if the Fixed Rate is selected. As of August 31, 2003, $9,450 was outstanding on the Term Note with an average rate of 3.9%. Heritage Operating, L.P. and Allied each have a limited guarantee of $5,000 of principle plus all accrued and unpaid interest.
The Term Note contains certain restrictive covenants including limitations on substantial disposition of assets, changes in ownership of Bi-State and additional indebtedness, and requires the maintenance of certain financial ratios. At August 31, 2003, Bi-State was in compliance with all covenants. Substantially all of the assets of Bi-State secure the Term Note.
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
5. COMMITMENTS AND CONTINGENCIES:
Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2008. Certain of these leases contain renewal options and also contain escalation clauses, which are accounted for on a straight-line basis over the minimum lease term. Rental expense under these leases totaled approximately $121 and $120 for the years ended August 31, 2003 and 2002, respectively, and has been included in operating expenses in the accompanying statements of operations. Fiscal year future minimum lease commitments for such leases are $149 in 2004; $37 in 2005; $32 in 2006; $11 in 2007 and $0 thereafter.
Bi-State has entered into a supply agreement with Allied in which Bi-State agrees to purchase from Allied all of Bi-State’s requirements of propane delivered to and sold out of its plants at Allied’s established distributor cost plus freight charges to the destination with a minimum and maximum quantity per year. The term of this contract expires March 2004, with a year-to year renewal option.
Bi-State is a party to various legal proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against Bi-State. In the opinion of management, all such matters are covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of Bi-State.
6. PARTNERS’ CAPITAL:
The Partnership Agreement between the Partners contains specific provisions for the maintenance of the Partner’s capital accounts. The Partnership Agreement specifies that the profits and losses of Bi-State be shared equally by the Partners, and covered or distributed from time to time, as the Partners shall agree. The initial contribution was based on Allied’s prior partnership interest and Heritage Bi-State’s acquisition basis that causes amortization and depreciation allocation differences to each Partner. Due to the valuation differences of the Partners’ initial contributions, the initial capital accounts were not equal, but subsequent changes in the capital account are subject to adjustment to equalize the Partner’s capital accounts. Excess cash, as agreed by the Partners, shall be distributed annually or as the Partners shall otherwise agree. Total distributions to the Partners were $1,070 and $800 for the years ended August 31, 2003 and 2002, respectively.
7. PROFIT SHARING AND 401(K) SAVINGS PLAN:
Bi-State sponsored a profit sharing and 401(k) savings plan, which covers all employees subject to service period requirements up until December 31, 2002, at which time the Plan merged with the profit sharing and 401(k) saving plan sponsored by Heritage Operating L.P. (collectively referred to as the “Plans”). Annual contributions to the Plans for Bi-State employees, if any, are discretionary, and must be agreed upon in writing by both Partners. Employer matching contributions are calculated using a discretionary formula based on employee contributions. Bi-State did not recognize any expense under the profit sharing provisions of either of the Plans during the years ended August 31, 2003 or 2002. Bi-State made matching contributions of $84 and $76, to the Plans for the years ended August 31, 2003 and 2002, respectively, which have been included in operating expenses in the accompanying statements of operations.
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Index to Financial Statements
BI-STATE PROPANE
NOTES TO FINANCIAL STATEMENTS—(Continued)
(Dollar amounts in thousands)
(Unaudited as to 2003 information)
8. RELATED PARTY TRANSACTIONS:
Bi-State entered into an Administrative Agreement with Heritage Bi-State and a Supply Agreement with Allied. Heritage Bi-State performs all the administrative functions on behalf of Bi-State including, but not limited to, accounting, insurance, cash management, training and employee benefits. In consideration of the services provided by Heritage Bi-State, Bi-State pays a negotiated fee, plus any specific charges as described by the Administrative Agreement to Heritage Bi-State. These costs totaled $751 and $536, for the years ended August 31, 2003 and 2002, respectively. An interest bearing receivable/payable account is maintained to monitor the net cash due between Heritage Bi-State and Bi-State. Heritage Bi-State agrees to advance funds necessary to provide for Bi-State’s working capital needs on a daily basis. These advances are reflected in the receivable/payable account. All cash collected by Bi-State is transferred to Heritage Bi-State’s depository account on a daily basis and is also reflected in the same receivable/payable account. This account is included in accounts receivable from affiliates on the balance sheet. The interest is based on the amount equal to the rate Heritage Operating L.P. pays on its working capital line of credit (2.49125% at August 31, 2003). The net interest charged by Bi-State to Heritage Bi-State on the receivable due from Heritage Bi-State was $40 and $62 for the years ended August 31, 2003 and 2002, respectively. The Supply Agreement calls for Bi-State to purchase from Allied all of Bi-State’s requirements of propane delivered to and sold out of its plants at Allied’s established distributor cost plus freight charges to the destination. Total purchases under this agreement by Bi-State were 16,977,000 gallons and 12,775,000 gallons, for the years ended August 31, 2003 and 2002, respectively for a total cost of $11,975 and $7,480, for the years ended August 31, 2003 and 2002, respectively.
9. SUBSEQUENT EVENTS:
On December 24, 2003, Heritage Operating, L.P. purchased the 50% interest in Bi-State Propane that it did not previously own, in exchange for 435,420 common units of Energy Transfer Partners, L.P. (formerly Heritage Propane, L.P.).
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Index to Financial Statements
Board of Directors and Stockholder
TXU Fuel Company
We have audited the accompanying balance sheets of TXU Fuel Company (the “Company”) as of December 31, 2003 and 2002 and the related statements of operations and comprehensive income, shareholder’s equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the such financial statements referred to above present fairly, in all material respects, the financial position of TXU Fuel Company as of December 31, 2003 and 2002 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the financial statements, the Company changed its method of accounting for asset retirement obligations in 2003 in connection with the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”
/s/ Deloitte & Touche LLP
Dallas, Texas
June 11, 2004
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Index to Financial Statements
BALANCE SHEETS
DECEMBER 31, 2003 AND 2002
| 2003 |
2002 |
|||||||
| (Dollars in thousands) | ||||||||
| ASSETS | ||||||||
| CURRENT ASSETS: |
||||||||
| Cash |
$ | 358 | $ | 110 | ||||
| Accounts receivable |
4,967 | 3,158 | ||||||
| Exchange gas receivable |
11,542 | 6,802 | ||||||
| Material and supplies |
873 | 606 | ||||||
| Accumulated deferred income taxes |
599 | 566 | ||||||
| Other current assets |
262 | 320 | ||||||
| Total current assets |
18,601 | 11,562 | ||||||
| PROPERTY, PLANT AND EQUIPMENT: |
||||||||
| Gas pipelines |
288,637 | 288,487 | ||||||
| Less accumulated depreciation |
186,443 | 187,614 | ||||||
| Net of accumulated depreciation |
102,194 | 100,873 | ||||||
| Construction work in progress |
2,086 | 2,718 | ||||||
| Net property, plant and equipment |
104,280 | 103,591 | ||||||
| INVESTMENTS |
875 | 653 | ||||||
| OTHER NONCURRENT ASSETS |
169 | 471 | ||||||
| TOTAL |
$ | 123,925 | $ | 116,277 | ||||
| LIABILITIES AND SHAREHOLDER’S EQUITY | ||||||||
| CURRENT LIABILITIES: |
||||||||
| Advances from affiliates |
$ | 43,819 | $ | 59,202 | ||||
| Accounts payable: |
||||||||
| Affiliates |
1,199 | 6,660 | ||||||
| Other |
3,514 | 4,184 | ||||||
| Exchange gas payable |
2,595 | 1,824 | ||||||
| Accrued taxes |
2,723 | 2,754 | ||||||
| Other current liabilities |
758 | 716 | ||||||
| Total current liabilities |
54,608 | 75,340 | ||||||
| ACCUMULATED DEFERRED INCOME TAXES |
12,739 | 11,800 | ||||||
| INVESTMENT TAX CREDITS |
1,134 | 1,277 | ||||||
| PENSIONS AND OTHER POSTRETIREMENT BENEFITS |
3,271 | 3,447 | ||||||
| OTHER NONCURRENT LIABILITIES AND DEFERRED CREDITS |
1,172 | 1,293 | ||||||
| Total liabilities |
72,924 | 93,157 | ||||||
| COMMITMENTS AND CONTINGENCIES (Note 6) |
||||||||
| SHAREHOLDER’S EQUITY: |
||||||||
| Common stock without par value—500,000 authorized shares; 100,000 outstanding shares |
2,016 | 2,016 | ||||||
| Retained earnings |
49,045 | 21,308 | ||||||
| Accumulated other comprehensive loss, net of tax effects |
(60 | ) | (204 | ) | ||||
| Total shareholder’s equity |
51,001 | 23,120 | ||||||
| TOTAL |
$ | 123,925 | $ | 116,277 | ||||
See notes to financial statements.
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Index to Financial Statements
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Years Ended December 31, 2003 and 2002
| 2003 |
2002 |
|||||||
| (Dollars in thousands) | ||||||||
| OPERATING REVENUES: |
||||||||
| Affiliates |
$ | 44,448 | $ | 54,427 | ||||
| Non-affiliates |
18,902 | 10,285 | ||||||
| Total operating revenues |
63,350 | 64,712 | ||||||
| COSTS AND EXPENSES: |
||||||||
| Cost of delivery and operating costs |
10,213 | 15,556 | ||||||
| Depreciation |
4,753 | 4,756 | ||||||
| Selling, general and administrative expenses |
4,764 | 5,548 | ||||||
| Franchise and revenue-based taxes |
392 | 370 | ||||||
| Other deductions |
— | 3 | ||||||
| Interest income |
(93 | ) | (8 | ) | ||||
| Interest expense and related charges: |
||||||||
| Interest on advances from affiliates |
1,519 | 2,186 | ||||||
| Other interest |
— | 20 | ||||||
| Total costs and expenses |
21,548 | 28,431 | ||||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES |
41,802 | 36,281 | ||||||
| INCOME TAX EXPENSE |
15,329 | 14,973 | ||||||
| INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES |
26,473 | 21,308 | ||||||
| CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE—Net of tax effect |
1,264 | — | ||||||
| NET INCOME |
27,737 | 21,308 | ||||||
| OTHER COMPREHENSIVE INCOME: |
||||||||
| Minimum pension liability adjustment, net of tax expense of $78 and |
144 | (204 | ) | |||||
| COMPREHENSIVE INCOME |
$ | 27,881 | $ | 21,104 | ||||
See notes to financial statements.
F-253
Table of Contents
Index to Financial Statements
STATEMENTS OF SHAREHOLDER’S EQUITY
Years Ended December 31, 2003 and 2002
| Common Stock |
Accumulated Loss |
Retained Earnings |
Total |
||||||||||||||
| Shares |
Amount |
||||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
| BALANCE—January 1, 2002 |
$ | 100,000 | $ | 2,016 | $ | — | $ | — | $ | 2,016 | |||||||
| Net income |
21,308 | 21,308 | |||||||||||||||
| Adjustment for minimum pension liability—net of taxes |
— | — | (204 | ) | — | (204 | ) | ||||||||||
| BALANCE—December 31, 2002 |
100,000 | 2,016 | (204 | ) | 21,308 | 23,120 | |||||||||||
| Net income |
27,737 | 27,737 | |||||||||||||||
| Adjustment for minimum pension liability—net of taxes |
— | — | 144 | — | 144 | ||||||||||||
| BALANCE—December 31, 2003 |
$ | 100,000 | $ | 2,016 | $ | (60 | ) | $ | 49,045 | $ | 51,001 | ||||||
See notes to financial statements.
F-254
Table of Contents
Index to Financial Statements
STATEMENTS OF CASH FLOWS
Years Ended December 31, 2003 and 2002
| 2003 |
2002 |
|||||||
| (Dollars in thousands) | ||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Income before cumulative effect of change in accounting principles: |
$ | 26,473 | $ | 21,308 | ||||
| Adjustments to reconcile net income to cash provided by operating activities: |
||||||||
| Depreciation |
4,753 | 4,756 | ||||||
| Deferred income taxes and investment tax credits—net |
1 | 1,955 | ||||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable: |
||||||||
| Affiliates receivable/payable—net |
(5,461 | ) | 46,208 | |||||
| Other |
(1,809 | ) | (1,499 | ) | ||||
| Materials and supplies |
(267 | ) | 29,320 | |||||
| Accounts payable other |
(670 | ) | (33,649 | ) | ||||
| Other assets |
(4,380 | ) | (2,439 | ) | ||||
| Other liabilities |
710 | (737 | ) | |||||
| Net cash provided by operating activities |
19,350 | 65,223 | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES— |
||||||||
| Net repayments to parent and affiliates |
(15,383 | ) | (58,932 | ) | ||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Capital expenditures |
(3,429 | ) | (6,214 | ) | ||||
| Other |
(290 | ) | 32 | |||||
| Net cash used in investing activities |
(3,719 | ) | (6,182 | ) | ||||
| NET CHANGE IN CASH |
248 | 109 | ||||||
| CASH—Beginning of year |
110 | 1 | ||||||
| CASH—End of year |
$ | 358 | $ | 110 | ||||
| SUPPLEMENTAL CASH FLOW DISCLOSURES: |
||||||||
| Cash paid for interest |
$ | (1,543 | ) | $ | (2,334 | ) | ||
| Cash paid for income taxes |
$ | (17,640 | ) | $ | (4,522 | ) | ||
See notes to financial statements.
F-255
Table of Contents
Index to Financial Statements
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2003 AND 2002
1. Significant Accounting Policies
General—TXU Fuel Company (the “Company”) is a wholly-owned subsidiary of TXU Energy Company LLC, which is a wholly-owned subsidiary of TXU Corp.
The Company owns a natural gas pipeline system, and stores and delivers fuel gas for the benefit of TXU US Holdings Company (“US Holdings”), formerly TXU Electric Company, a wholly-owned subsidiary of TXU Corp and third-parties. The Company may not engage in other substantial activities without the consent of US Holdings.
The Company has adopted the National Association of Regulatory Utility Commissioners Uniform System of Accounts as prescribed by the Railroad Commission of Texas. Since the Company provides services to US Holdings, its books and records are subject to review by various regulators.
Basis of Presentation—The financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the US. In the opinion of management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All dollar amounts in the financial statements and tables in the notes are stated in thousands of US Dollars unless otherwise indicated.
Use of Estimates—Preparation of the Company’s financial statements requires management to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense during the periods. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments were made to previous estimates or assumptions during the current year.
Revenue Recognition—Gas pipeline transportation revenues are recognized as services are provided to customers based on estimated volumes subsequently confirmed by measurement reports. Unbilled revenues totaled $1.9 million and $.9 million at December 31, 2003 and 2002, respectively. The Company retains negotiated percentages of fuel transported for customers as an allowance for fuel used in the transportation of gas and other unaccounted for quantities of gas. The Company classifies fuel retained from customers as a credit to cost of delivery and operating costs in the statement of income and values such amounts based on current market prices at the time of the retention.
Investments—Assets related to employee benefit plans are held to satisfy deferred compensation liabilities and are recorded at market value.
Gas Pipelines—Gas pipeline is stated at original cost less accumulated depreciation. The cost of property additions includes labor and materials, applicable overhead and payroll-related costs. The Company does not capitalize an allowance for funds used during construction.
Depreciation of Property, Plant and Equipment—Depreciation of the Company’s property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation as a percent of average depreciable property approximated 1.8% for 2003 and 2002.
Impairment of Long-lived Assets—The Company evaluates the carrying value of long-lived assets to be held and used when events and circumstances warrant such a review. The carrying value of long-lived assets
F-256
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
would be considered impaired when the projected undiscounted cash flows are less than carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair market value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. (See Changes in Accounting Standards below.)
Income Taxes—Investment tax credits are amortized to income over the estimated service lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Current receivables and/or payables to affiliates include amounts for income taxes due from or to TXU Corp.
Defined Benefit Pension Plans and Other Postretirement Benefit Plans—The Company is a participating employer in the defined benefit pension plan sponsored by TXU Corp. The Company also participates with TXU Corp. and other affiliated subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the Company. See Note 5 for information regarding retirement plans and other postretirement benefits.
Franchise and Revenue-Based Taxes—Franchise and revenue-based taxes such as gross receipts taxes are not a “pass through” item such as sales and excise taxes. Gross receipts taxes are assessed to the Company by state and local governmental bodies, based on revenues, as a cost of doing business. The Company records gross receipts tax as an expense. Rates charged to customers by the Company are intended to recover the taxes, but the Company is not acting as an agent to collect the taxes from customers.
Exchange Gas Receivable and Payable—Represents over-deliveries and under-deliveries of gas with counterparties and is revalued at current market prices.
Changes in Accounting Standards—Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. As a result of the implementation of SFAS No. 143 the Company recorded a cumulative effect of changes in accounting principles as of January 1, 2003 of $1.3 million (net tax of $.7 million). (See Note 2 for a discussion of the impact of this accounting standard.)
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, became effective on January 1, 2002. SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, for long-lived assets to be disposed of by sale and resolves significant implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 did not impact the financial statements for 2002.
SFAS No. 145, Rescission of FA SB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections, was issued in April 2002 and became effective on January 1, 2003. One of the provisions of this statement was the rescission of SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt. Any gain or loss on the early extinguishment of debt that was classified as an extraordinary item in prior periods in accordance with SFAS No. 4 would be reclassified if it did not meet the criteria of an extraordinary item as defined by Accounting Principles Board Opinion 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. The adoption of SFAS No. 145 did not impact the financial statements.
F-257
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, became effective on January 1, 2003. SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized only when the liability is incurred and measured initially at fair value. The adoption of SFAS No. 146 did not impact the financial statements.
Financial Accounting Standards Board Interpretation (“FIN”) No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others—an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34, was issued in November 2002 and requires recording of the fair value of guarantees upon issuance or modification after December 31, 2002. The interpretation also requires expanded disclosures of guarantees. The adoption of FIN 45 did impact the financial statements.
FIN No. 46, Consolidation of Variable Interest Entities, was issued in January 2003. FIN No. 46 provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. On October 8, 2003, the FASB decided to defer implementation of FIN No. 46 until the fourth quarter of 2003. This deferral only applies to variable interest entities that existed prior to February 1, 2003. FIN 46R was issued in December 2003 and replaced FIN 46. FIN 46R expands and clarifies the guidance originally contained in FIN 46, regarding consolidation of variable interest entities. The implementation of FIN No. 46R did not impact the financials statements.
SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, was issued in April 2003 and became effective for contracts entered into or modified after June 30, 2003. SFAS 149 clarifies what contracts may be eligible for the normal purchase and sale exception, the definition of a derivative and the treatment in the statement of cash flows when a derivative contains a financing component. Also, Emerging Issues Task Force (“EITF”) 03-11 was issued in July 2003 and became effective October 1, 2003 and, among other things, discussed the nature of certain power contracts. The implementation of SFAS 149 and EITF 03-11 did not impact the financial statements.
SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, was issued in May 2003 and became effective June 1, 2003 for new financial instruments and July 1, 2003 for existing financial instruments. SFAS 150 requires that mandatory redeemable preferred securities be classified as liabilities beginning July 1, 2003. The implementation of SFAS 150 did not impact the financial statements.
EITF 01-8 was issued in May 2003 and is effective prospectively for arrangements that are new, modified or committed to beginning July 1, 2003. This guidance requires that certain types of arrangements be accounted for as leases, including tolling and power supply contracts, take-or-pay contracts and service contracts involving the use of specific property and equipment. The adoption of this change did not impact the financial statements.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was enacted in December 2003. FASB Staff Position 106-1, issued in January 2004, allowed for, but did not require, deferral of the accounting for the effects of the Medicare Act. TXU Corp. elected not to defer accounting for the federal subsidy under the Medicare Act and recognized a $1.9 million net reduction in postretirement benefit expense its the 2003 financial statements. For the year ended December 31, 2003, the effect of adoption of the Medicare Act was a reduction of approximately $6 thousand in the Company’s allocated postretirement benefit costs.
For accounting standards not yet adopted, the Company is evaluating the potential impact on its financial position and results of operations.
F-258
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
2. Cumulative Effect of Change in Accounting Principles
The adoption of SFAS No. 143 resulted in a credit of $1.3 million, net of $.7 million tax effect to earnings for the cumulative effect of the new accounting principle.
SFAS No. 143 became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period of its inception. For the Company such liabilities would relate to gas pipelines. The Company has determined that no such costs meet the liability recognition criteria of SFAS No. 143. The Company previously included estimated asset retirement costs in its depreciation rates. As the new accounting rule required retrospective application to the inception of the liability, if applicable, the effects of the adoption reflect the reversal of previously recorded depreciation expense for the estimated asset retirement costs previously reflected in accumulated depreciation at the date of adoption.
The following table summarizes the impact as of January 1, 2003 of adopting SFAS No. 143:
| Increase in property, plant and equipment—net |
$ | 1,944 | ||
| Increase in accumulated deferred income taxes |
(680 | ) | ||
| Cumulative effect of change in accounting principles |
$ | 1,264 | ||
On a pro forma basis, assuming SFAS 143 had been adopted at the beginning of the period, earnings for the year ended December 31, 2002 would have increased by approximately $400 thousand after-tax.
3. Affiliate Transactions
The advances from/to affiliates are in the form of demand notes payable/receivable, which bear interest at a rate equal to the weighted average cost of all outstanding short-term indebtedness of TXU Corp. or a published rate for similar borrowings when TXU Corp. has no outstanding short-term borrowings. The weighted average interest rates on such borrowings were 2.79% and 2.34% on December 31, 2003 and 2002, respectively.
TXU Business Services Company, a subsidiary of TXU Corp., billed the Company $1.4 million and $2.4 million in 2003 and 2002, respectively, for financial, accounting, information technology, personnel, procurement and other administrative services at cost. Accounts receivable from and payable to affiliates are settled in the normal course of business. Accounts receivable from affiliates were $3.7 million and $2.0 million at December 31, 2003 and 2002, respectively. Accounts payable to affiliates were $4.9 million and $8.6 million at December 31, 2003 and 2002, respectively.
F-259
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
4. Income Taxes
The components of the provision for income taxes are as follows:
| 2003 |
2002 |
|||||||
| Current: |
||||||||
| Federal |
$ | 13,983 | $ | 11,503 | ||||
| State |
1,345 | 1,515 | ||||||
| Total |
15,328 | 13,018 | ||||||
| Deferred: |
||||||||
| Federal |
157 | 61 | ||||||
| State—other |
(13 | ) | 2,037 | |||||
| Total |
144 | 2,098 | ||||||
| Investment tax credits |
(143 | ) | (143 | ) | ||||
| Total |
$ | 15,329 | $ | 14,973 | ||||
Investment tax credit amortization is the primary difference between the expected income tax expense at the federal statutory rate of 35% and actual income tax expense.
The components of deferred tax assets and deferred tax liabilities are as follows:
| 2003 |
2004 |
|||||||
| Current deferred tax assets—other |
$ | 599 | $ | 566 | ||||
| Noncurrent: |
||||||||
| Deferred tax assets: |
||||||||
| Alternative minimum tax |
5,163 | 5,197 | ||||||
| Employee benefit plans |
1,550 | 1,578 | ||||||
| Capitalized construction costs |
1,413 | 1,211 | ||||||
| Unamortized investment tax credits |
397 | 447 | ||||||
| Other |
1,210 | 831 | ||||||
| Total noncurrent deferred tax assets |
9,733 | 9,264 | ||||||
| Deferred tax liabilities: |
||||||||
| Depreciation differences |
19,446 | 18,502 | ||||||
| State |
2,270 | 2,292 | ||||||
| Other |
756 | 270 | ||||||
| Total noncurrent deferred tax liabilities |
22,472 | 21,064 | ||||||
| Net noncurrent deferred tax liability |
$ | (12,739 | ) | $ | (11,800 | ) | ||
At December 31, 2003, the Company had approximately $5.2 million of alternative minimum tax credit carryforwards available to offset future tax payments.
F-260
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
A reconciliation between the expected tax computed using the US federal statutory income tax rate and the provision (benefit) for income taxes is as follows:
| 2003 |
2004 |
|||||||
| Statutory federal income tax |
$ | 14,631 | $ | 12,698 | ||||
| State and local income taxes—net of federal income tax effect |
866 | 2,309 | ||||||
| Amortization of investment tax credits |
(143 | ) | (143 | ) | ||||
| Prior year adjustments |
(81 | ) | 36 | |||||
| Other |
56 | 73 | ||||||
| Total |
$ | 15,329 | $ | 14,973 | ||||
5. Retirement Plans and Other Postretirement Benefits
The Company is a participating employer in the TXU Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by TXU Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (“Code”), and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). Employees are eligible to participate in the Retirement Plan upon their completion of one year of service and the attainment of age 21. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a cash balance formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits, or (ii) a traditional defined benefit formula based on years of service and the average earnings of the three years of highest earnings.
All eligible employees hired after January 1, 2002 will participate under the cash balance formula. Certain employees who, prior to January 1, 2002, participated under the traditional defined benefit formula, continue their participation under that formula. Under the cash balance formula, future increases in earnings will not apply to prior service costs. It is TXU Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations. Such contributions, when made, are intended to provide not only for benefits attributed to service to date, but also those expected to be earned in the future.
The net periodic pension cost applicable to the Company was $67 thousand for 2003 and $28 thousand for 2002. There were no Company contributions paid to the plan in 2003 and 2002.
In addition, Company employees are eligible to participate in a qualified savings plan, the TXU Thrift Plan (“Thrift Plan”). This plan is a participant-directed defined contribution profit sharing plan qualified under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan includes an employee stock ownership component. Under the terms of the Thrift Plan, as amended effective January 1, 2002, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the maximum amount of their regular salary or wages permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the cash balance formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the traditional defined benefit formula of the Retirement Plan. Employer matching contributions are invested in TXU Corp. common stock. The Company’s contributions to the Thrift Plan aggregated $46 thousand in 2003 and $35 thousand in 2002.
F-261
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2003 AND 2002
In addition to the Retirement Plan and the Thrift Plan, the Company participates with TXU Corp. and certain other affiliated subsidiaries of TXU Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the at retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service. The estimated net periodic postretirement benefits cost other than pensions applicable to the Company was $223 thousand for 2003 and $199 thousand for 2002. Contributions paid by the Company to fund postretirement benefits other than pensions were $305 thousand in 2003 and $260 thousand for 2002.
6. Commitments and Contingencies
Gas Purchase Contracts—At December 31, 2003, the Company had commitments for pipeline transportation and storage reservation fees as shown in the table below:
| Year Ending December 31, | |||
| 2004 |
$ | 24,417 | |
| 2005 |
7,026 | ||
| 2006 |
5,665 | ||
| 2007 |
4,240 | ||
| 2008 |
457 | ||
| Thereafter |
5,926 | ||
| Total |
$ | 47,731 | |
Litigation—The Company is a party, in the ordinary course of business, to certain claims and litigation. The settlement of such matters is not expected to have a material adverse impact on its consolidated financial position, results of operations or cash flows of the Company.
7. Fair Value of Financial Instruments
The fair value of all financial instruments, principally cash and accounts receivable is not materially different than their related carrying amounts.
8. Sale of the Company
On June 2, 2004, the Company’s parent completed the sale of the assets of the Company to an outside party. As part of the transaction the parent will enter into an eight year transportation agreement with the new owner to transport gas to the parent’s generating assets.
F-262
Table of Contents
Index to Financial Statements
BALANCE SHEET
March 31, 2004 (Unaudited)
| (Dollars in thousands) |
||||
| ASSETS | ||||
| CURRENT ASSETS: |
||||
| Cash |
$ | 48 | ||
| Accounts receivable |
3,641 | |||
| Exchange gas receivable |
15,818 | |||
| Material and supplies—at average cost |
843 | |||
| Other current assets |
517 | |||
| Total current assets |
20,867 | |||
| PROPERTY, PLANT AND EQUIPMENT: |
||||
| Gas plant |
287,292 | |||
| Less accumulated depreciation |
187,218 | |||
| Net of accumulated depreciation |
100,074 | |||
| Construction work in progress |
2,125 | |||
| Net property, plant and equipment |
102,199 | |||
| INVESTMENTS |
871 | |||
| OTHER NONCURRENT ASSETS |
28 | |||
| TOTAL |
$ | 123,965 | ||
| LIABILITIES AND SHAREHOLDER’S EQUITY | ||||
| CURRENT LIABILITIES: |
||||
| Advances from affiliates |
$ | 33,511 | ||
| Accounts payable: |
||||
| Affiliates |
4,645 | |||
| Other |
1,106 | |||
| Exchange gas payable |
6,489 | |||
| Accrued taxes |
2,340 | |||
| Other current liabilities |
827 | |||
| Total current liabilities |
48,918 | |||
| ACCUMULATED DEFERRED INCOME TAXES |
12,995 | |||
| INVESTMENT TAX CREDITS |
1,098 | |||
| PENSIONS AND OTHER POSTRETIREMENT BENEFITS |
3,237 | |||
| OTHER NONCURRENT LIABILITIES AND DEFERRED CREDITS |
1,898 | |||
| Total liabilities |
68,146 | |||
| COMMITMENTS AND CONTINGENCIES (Note 5) |
||||
| SHAREHOLDER’S EQUITY |
||||
| Common stock without par value—500,000 authorized shares; 100,000 outstanding shares |
2,016 | |||
| Retained earnings |
53,863 | |||
| Accumulated other comprehensive loss, net of tax effects |
(60 | ) | ||
| Total shareholder’s equity |
55,819 | |||
| TOTAL |
$ | 123,965 | ||
See notes to financial statements.
F-263
Table of Contents
Index to Financial Statements
STATEMENTS OF INCOME
Three Months Ended March 31, 2004 and 2003
(Unaudited)
| 2004 |
2003 | |||||
| (Dollars in thousands) | ||||||
| OPERATING REVENUES: |
||||||
| Affiliates |
$ | 4,451 | $ | 8,091 | ||
| Non-affiliates |
7,288 | 4,005 | ||||
| Total operating revenues |
11,739 | 12,096 | ||||
| COSTS AND EXPENSES: |
||||||
| Cost of delivery and operating costs |
1,596 | 5,248 | ||||
| Depreciation |
1,465 | 1,196 | ||||
| Selling, general and administrative expenses |
604 | 1,440 | ||||
| Franchise and revenue-based taxes |
95 | 43 | ||||
| Interest expense and related charges: |
||||||
| Interest on advances from affiliates |
289 | 359 | ||||
| Other interest |
25 | 1 | ||||
| Total costs and expenses |
4,074 | 8,287 | ||||
| INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES |
7,665 | 3,809 | ||||
| INCOME TAX EXPENSE |
2,847 | 1,498 | ||||
| INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES |
4,818 | 2,311 | ||||
| CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES: |
||||||
| Net of tax effect |
— | 1,264 | ||||
| NET INCOME |
$ | 4,818 | $ | 3,575 | ||
See notes to financial statements.
F-264
Table of Contents
Index to Financial Statements
STATEMENTS OF CASH FLOWS
Three Months Ended March 31, 2004 and 2003
(Unaudited)
| 2004 |
2003 |
|||||||
| (Dollars in thousands) | ||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
| Income before cumulative effect of change in accounting principles: |
$ | 4,818 | $ | 2,311 | ||||
| Adjustments to reconcile net income to cash provided by operating activities: |
||||||||
| Depreciation |
1,465 | 1,196 | ||||||
| Deferred income taxes and investment tax credits—net |
818 | 641 | ||||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable: |
||||||||
| Affiliates |
0 | (760 | ) | |||||
| Other |
1,326 | (210 | ) | |||||
| Inventories |
30 | (39 | ) | |||||
| Accounts payable |
||||||||
| Affiliates |
3,446 | (6,660 | ) | |||||
| Other |
(2,408 | ) | (1,630 | ) | ||||
| Other assets |
(4,390 | ) | (2,946 | ) | ||||
| Other liabilities |
4,273 | 4,170 | ||||||
| Cash provided by (used in) operating activities |
9,378 | (3,927 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES— |
||||||||
| Net (payments to) advances from parent and affiliates |
(10,308 | ) | 4,672 | |||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
| Capital expenditures |
674 | (755 | ) | |||||
| Investments |
(54 | ) | 35 | |||||
| Cash provided by (used in) investing activities |
620 | (720 | ) | |||||
| NET CHANGE IN CASH |
(310 | ) | 25 | |||||
| CASH—Beginning balance |
358 | 110 | ||||||
| CASH—Ending balance |
48 | 135 | ||||||
See notes to financial statements.
F-265
Table of Contents
Index to Financial Statements
NOTES TO FINANCIAL STATEMENTS
Three Months Ended March 31, 2004 and 2003 (Unaudited)
1. Significant Accounting Policies and Business
General—TXU Fuel Company (the “Company”) is a wholly-owned subsidiary of TXU Energy Company LLC, which is a wholly-owned subsidiary of TXU Corp.
The Company owns a natural gas pipeline system, and stores and delivers fuel gas for the benefit of TXU US Holdings Company (“US Holdings”), formerly TXU Electric Company, a wholly-owned subsidiary of TXU Corp., and for third parties. The Company may not engage in other substantial activities without the consent of US Holdings.
The Company has adopted the National Association of Regulatory Utility Commissioners Uniform System of Accounts as prescribed by the Railroad Commission of Texas. Since the Company provides services to US Holdings, its books and records are subject to review by various regulators.
Basis of Presentation—The interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the US (“US GAAP”) and on the same basis as the audited financial statements for the year ended December 31, 2003. In the opinion of management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes for the year ended December 31, 2003. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in thousands of US Dollars unless otherwise indicated. There were no other components of comprehensive income other than net income.
Use of Estimates—Preparation of the Company’s financial statements requires management to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense during the periods. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments were made to previous estimates or assumptions during the current year.
Revenue Recognition—Gas pipeline transportation revenues are recognized as services are provided to customers based on estimated volumes subsequently confirmed by measurement reports.
Investments—Assets related to employee benefit plans are held to satisfy deferred compensation liabilities and are recorded at market value.
Gas Pipelines—Gas pipeline is stated at original cost. The cost of property additions includes labor and materials, applicable overhead and payroll-related costs. The Company does not capitalize an allowance for funds used during construction.
Impairment of Long-lived Assets—The Company evaluates the carrying value of long-lived assets to be held and used when events and circumstances warrant such a review. The carrying value of long-lived assets would be considered impaired when the projected undiscounted cash flows are less than carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair market
F-266
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
Three Months Ended March 31, 2004 and 2003 (Unaudited)
value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. (See Changes in Accounting Standards below.)
Income Taxes—Investment tax credits are amortized to income over the estimated service lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Current receivables and/or payables to affiliates include amounts for income taxes due from or to TXU Corp.
2. Cumulative Effect of Changes in Accounting Principles
The adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143 resulted in a credit of $1.3 million, net of $.7 million tax effect to earnings for the cumulative effect of the new accounting principle for the three months ended March 31, 2003.
SFAS 143 became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period of its inception. For the Company such liabilities would relate to gas pipelines. The Company has determined that no such costs meet the liability recognition criteria of SFAS No. 143. The Company previously included estimated asset retirement costs in its depreciation rates. As the new accounting rule required retrospective application to the inception of the liability, if applicable, the effects of the adoption reflect the reversal of previously recorded depreciation expense for the estimated asset retirement costs previously reflected in accumulated depreciation at the date of adoption.
The following table summarizes the impact as of January 1, 2003 of adopting SFAS 143:
| Increase in property, plant and equipment—net |
$ | 1,944 | ||
| Increase in accumulated deferred income taxes |
(680 | ) | ||
| Cumulative effect of change in accounting principles |
$ | 1,264 |
3. Affiliate Transactions
The advances from/to affiliates are in the form of demand notes payable/receivable, which bear interest at a rate equal to the weighted average cost of all outstanding short-term indebtedness of TXU Corp. or a published rate for similar borrowings when TXU Corp. has no outstanding short-term borrowings. The average interest rate on such borrowings was 2.86% and 2.33% for the first three months of 2004 and 2003, respectively.
TXU Business Services Company, an affiliate of the Company, billed the Company $22,000 and $405,000 in 2004 and 2003, respectively, for financial, accounting, information technology, personnel, procurement and other administrative services at cost. Accounts receivable from and payable to affiliates are settled in the normal course of business.
4. Retirement Plan and Other Postretirement Benefits
The Company is a participating employer in the TXU Retirement Plan, a defined benefit pension plan sponsored by TXU Corp. The Company also participates with TXU Corp. and other affiliated subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The allocated net periodic pension cost and net periodic postretirement benefits cost other than pensions applicable to the Company were $51,000 and $95,000 for the three months ended March 31, 2004 and 2003, respectively.
F-267
Table of Contents
Index to Financial Statements
TXU FUEL COMPANY
NOTES TO FINANCIAL STATEMENTS—(Continued)
Three Months Ended March 31, 2004 and 2003 (Unaudited)
At March 31, 2004, the Company estimates that its total contributions to the pension plan and other postretirement benefit plans for the remainder of 2004 will not be materially different than previously disclosed in the 2003 financial statements.
5. Contingencies
The Company is a party, in the ordinary course of business, to certain claims and litigation. The settlement of such matters is not expected to have a material adverse impact on the financial position, results of operations or cash flows of the Company.
6. Sale of the Company
During June 2004, the Company’s parent completed the sale of the assets of the Company to an outside party. As part of the transaction, the parent will have an eight-year transportation agreement with the new owner to transport gas to the parent’s generation plants.
F-268
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Partners of
HPL Consolidation LP:
We have audited the accompanying consolidated balance sheets of HPL Consolidation LP (“the Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows and partners’ capital for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of HPL Consolidation LP as of December 31, 2004, and 2003 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Houston, Texas
March 15, 2005
F-269
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
| Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| Operating Revenues |
$ | 3,069,160 | $ | 3,006,444 | $ | 2,123,180 | ||||||
| Operating Revenues—Affiliated |
862,277 | 899,233 | 573,960 | |||||||||
| Total Operating Revenues |
3,931,437 | 3,905,677 | 2,697,140 | |||||||||
| Operating Expenses: |
||||||||||||
| Gas Purchases |
3,004,001 | 3,340,656 | 2,149,615 | |||||||||
| Gas Purchases—Affiliated |
760,294 | 464,463 | 388,193 | |||||||||
| Operation and Maintenance |
58,960 | 56,508 | 48,868 | |||||||||
| Administrative and General |
17,229 | 15,255 | 17,520 | |||||||||
| Asset Impairment |
— | 300,000 | — | |||||||||
| Parent Company Managerial and Professional |
5,512 | 4,991 | 5,372 | |||||||||
| Depreciation and Amortization |
10,655 | 15,149 | 13,246 | |||||||||
| Taxes Other Than Income Taxes |
13,275 | 8,838 | 11,705 | |||||||||
| Total Operating Expenses |
3,869,926 | 4,205,860 | 2,634,519 | |||||||||
| Operating Income (Loss) |
61,511 | (300,183 | ) | 62,621 | ||||||||
| Equity Loss of Nonconsolidated Subsidiary |
(683 | ) | (668 | ) | (249 | ) | ||||||
| Interest Income |
408 | — | — | |||||||||
| Interest Income—Affiliated |
2,294 | 2,542 | 4,874 | |||||||||
| Interest Expense |
(36 | ) | (70 | ) | (723 | ) | ||||||
| Interest Expense—Affiliated |
(227 | ) | — | — | ||||||||
| Nonoperating Gain |
3,453 | 213 | 538 | |||||||||
| Income (Loss) Before Income Taxes |
66,720 | (298,166 | ) | 67,061 | ||||||||
| Income Tax Expense (Credit) |
22,694 | (81,595 | ) | 23,604 | ||||||||
| Net Income (Loss) |
$ | 44,026 | $ | (216,571 | ) | $ | 43,457 | |||||
See Notes to Consolidated Financial Statements.
F-270
Table of Contents
Index to Financial Statements
CONSOLIDATED BALANCE SHEETS ASSETS
(in thousands)
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| CURRENT ASSETS: |
||||||||
| Cash and Cash Equivalents |
$ | 220 | $ | 2,891 | ||||
| Advances to Affiliates |
— | 93,868 | ||||||
| Accounts Receivable: |
||||||||
| Trade Receivables |
281,338 | 298,546 | ||||||
| Allowance for Uncollectible Accounts |
(1,348 | ) | (1,409 | ) | ||||
| Affiliated Companies |
34,091 | 39,450 | ||||||
| Gas Inventory |
221,075 | 3,095 | ||||||
| Materials and Supplies |
1,573 | 1,550 | ||||||
| Exchange Gas Receivables |
10,452 | 9,222 | ||||||
| Price-Risk Management Assets |
22,777 | 36,462 | ||||||
| Price-Risk Management Assets—Affiliated |
70,981 | 7,378 | ||||||
| Other |
730 | 824 | ||||||
| TOTAL CURRENT ASSETS |
641,889 | 491,877 | ||||||
| PROPERTY, PLANT AND EQUIPMENT, net |
399,649 | 280,989 | ||||||
| OTHER NONCURRENT ASSETS |
1,846 | 2,349 | ||||||
| EQUITY INVESTMENT—NONCONSOLIDATED SUBSIDIARY |
33,035 | 33,718 | ||||||
| LONG-TERM—PRICE-RISK MANAGEMENT ASSETS |
18,009 | 17,770 | ||||||
| LONG-TERM—PRICE-RISK MANAGEMENT ASSETS—AFFILIATED |
6,040 | 9,571 | ||||||
| DEFERRED INCOME TAX |
98,400 | 122,164 | ||||||
| TOTAL ASSETS |
$ | 1,198,868 | $ | 958,438 | ||||
See Notes to Consolidated Financial Statements.
F-271
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Index to Financial Statements
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND PARTNERS’ CAPITAL
(in thousands)
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| CURRENT LIABILITIES: |
||||||||
| Advances From Affiliates |
$ | 209,992 | $ | — | ||||
| Accounts Payable—Trade |
172,948 | 263,864 | ||||||
| Accounts Payable—Affiliated Companies |
86,636 | 47,405 | ||||||
| Taxes Accrued |
32,017 | 1,981 | ||||||
| Exchange Gas Payable |
12,747 | 11,994 | ||||||
| Price-Risk Management Liabilities |
21,474 | 25,715 | ||||||
| Other |
21,927 | 18,585 | ||||||
| TOTAL CURRENT LIABILITIES |
557,741 | 369,544 | ||||||
| NONCURRENT LIABILITIES |
12,104 | 18,855 | ||||||
| LONG-TERM PRICE-RISK MANAGEMENT LIABILITIES |
24,227 | 12,971 | ||||||
| PARTNERS’ CAPITAL |
||||||||
| Paid-in Capital |
740,485 | 772,747 | ||||||
| Accumulated Other Comprehensive Income (Loss) |
35,683 | (281 | ) | |||||
| Accumulated Deficit |
(171,372 | ) | (215,398 | ) | ||||
| TOTAL PARTNERS’ CAPITAL |
604,796 | 557,068 | ||||||
| TOTAL PARTNERS’ CAPITAL AND LIABILITIES |
$ | 1,198,868 | $ | 958,438 | ||||
See Notes to Consolidated Financial Statements.
F-272
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| OPERATING ACTIVITIES: |
||||||||||||
| Net Income (Loss) |
$ | 44,026 | $ | (216,571 | ) | $ | 43,457 | |||||
| Adjustments for Noncash Items: |
||||||||||||
| Impairment of Long-Lived Assets |
— | 300,000 | — | |||||||||
| Depreciation and Amortization |
10,655 | 15,149 | 13,246 | |||||||||
| Deferred Income Taxes |
4,398 | (81,111 | ) | 2,319 | ||||||||
| Fair Value of Price Risk Management Contracts |
(3,647 | ) | 7,093 | 4,942 | ||||||||
| Changes in Certain Current Items: |
||||||||||||
| Accounts Receivable |
17,147 | (36,087 | ) | (114,765 | ) | |||||||
| Accounts Receivable—Affiliated Companies |
5,359 | 47,954 | 304,030 | |||||||||
| Gas Inventory, Materials and Supplies |
(218,003 | ) | (2,201 | ) | (263 | ) | ||||||
| Accrued Taxes |
30,036 | (12,636 | ) | (1,663 | ) | |||||||
| Accounts Payable |
(90,916 | ) | 29,395 | 116,899 | ||||||||
| Accounts Payable—Affiliated Companies |
39,231 | (89,066 | ) | (86,713 | ) | |||||||
| Exchange Gas Payable (net) |
(477 | ) | (881 | ) | (7,335 | ) | ||||||
| Other (net) |
19,012 | (10,015 | ) | 2,032 | ||||||||
| Net Cash Flows From (Used For) Operating Activities |
(143,179 | ) | (48,977 | ) | 276,186 | |||||||
| INVESTING ACTIVITIES: |
||||||||||||
| Gross Property Additions |
(16,788 | ) | (25,427 | ) | (17,118 | ) | ||||||
| Acquisition of Bammel |
(115,000 | ) | — | — | ||||||||
| Other |
699 | 4,138 | — | |||||||||
| Net Cash Used For Investing Activities |
(131,089 | ) | (21,289 | ) | (17,118 | ) | ||||||
| FINANCING ACTIVITIES: |
||||||||||||
| Capital Contribution |
115,000 | 26,160 | — | |||||||||
| Return of Capital to Parent |
(147,262 | ) | — | (100,000 | ) | |||||||
| Change in Advances from/to Affiliates (net) |
303,859 | 59,697 | (123,267 | ) | ||||||||
| Dividend Paid to Parent |
— | (12,700 | ) | (38,000 | ) | |||||||
| Net Cash From (Used For) Financing Activities |
271,597 | 73,157 | (261,267 | ) | ||||||||
| NET INCREASE (DECREASE) IN CASH |
(2,671 | ) | 2,891 | (2,199 | ) | |||||||
| CASH AT BEGINNING OF PERIOD |
2,891 | — | 2,199 | |||||||||
| CASH AT END OF PERIOD |
$ | 220 | $ | 2,891 | $ | — | ||||||
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $0, $70 and $788 and cash paid to (refunds received from) Parent for income taxes was $(9,537), $12,546 and $20,342 in 2004, 2003 and 2002. See Note 9 for noncash investing activities.
See Notes to Consolidated Financial Statements.
F-273
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Index to Financial Statements
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands)
| Accumulated Other Comprehensive Income (Loss) |
Other Paid-In Capital |
Retained (Accumulated |
Total |
|||||||||||||
| December 31, 2001 |
$ | — | $ | 846,587 | $ | 8,416 | $ | 855,003 | ||||||||
| Dividends Paid to Parent |
(38,000 | ) | (38,000 | ) | ||||||||||||
| Return of Capital to Parent |
(100,000 | ) | (100,000 | ) | ||||||||||||
| TOTAL |
717,003 | |||||||||||||||
| COMPREHENSIVE INCOME (LOSS) |
||||||||||||||||
| NET INCOME |
43,457 | 43,457 | ||||||||||||||
| TOTAL COMPREHENSIVE INCOME |
43,457 | |||||||||||||||
| December 31, 2002 |
— | 746,587 | 13,873 | 760,460 | ||||||||||||
| Dividends Paid to Parent |
(12,700 | ) | (12,700 | ) | ||||||||||||
| Capital Contributions from Parent |
26,160 | 26,160 | ||||||||||||||
| TOTAL |
773,920 | |||||||||||||||
| COMPREHENSIVE INCOME (LOSS) |
||||||||||||||||
| Other Comprehensive Income (Loss), Cash Flow Hedges, net of $(151) Tax |
(281 | ) | (281 | ) | ||||||||||||
| NET LOSS |
(216,571 | ) | (216,571 | ) | ||||||||||||
| TOTAL COMPREHENSIVE LOSS |
(216,852 | ) | ||||||||||||||
| December 31, 2003 |
(281 | ) | 772,747 | (215,398 | ) | 557,068 | ||||||||||
| Capital Contributions from Parent |
115,000 | 115,000 | ||||||||||||||
| Return of Capital to Parent |
(147,262 | ) | (147,262 | ) | ||||||||||||
| TOTAL |
524,806 | |||||||||||||||
| COMPREHENSIVE INCOME (LOSS) |
||||||||||||||||
| Other Comprehensive Income (Loss), Cash Flow Hedges, net of $19,365 Tax |
35,964 | 35,964 | ||||||||||||||
| NET INCOME |
44,026 | 44,026 | ||||||||||||||
| TOTAL COMPREHENSIVE INCOME |
79,990 | |||||||||||||||
| December 31, 2004 |
$ | 35,683 | $ | 740,485 | $ | (171,372 | ) | $ | 604,796 | |||||||
See Notes to Consolidated Financial Statements.
F-274
Table of Contents
Index to Financial Statements
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. Organization and Summary of Significant Accounting Policies |
F-276 | |
| F-280 | ||
| F-281 | ||
| F-290 | ||
| F-291 | ||
| F-291 | ||
| F-293 | ||
| F-294 | ||
| F-296 | ||
| F-297 | ||
| F-297 | ||
| F-298 | ||
| F-299 | ||
F-275
Table of Contents
Index to Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Organization
Business Operations—HPL Consolidation LP (“We”, “Us”, or “HPL”) is a wholly owned subsidiary of American Electric Power Inc. (“AEP”). HPL was formed in November 2004 in connection with the acquisition of the Bammel storage field leased assets as further described in Note 3. HPL wholly owns the newly formed subsidiary HPL Storage GP, LLC (“HPL GP”), which owns the Bammel storage field assets and Houston Pipe Line Company LP (“HPC”). AEP acquired HPC from Enron Corporation on June 1, 2001. HPL is a fully integrated natural gas gathering, processing, storage, and transportation operation located in the state of Texas. HPL’s gathering and transportation assets include 4,200 miles of gas pipeline and the Bammel gas storage facility with approximately 130 billion cubic feet of capacity. In addition to the pipelines and storage assets, HPL owns a 50% interest in Mid Texas Pipeline Company (“Mid Texas”). Mid Texas’ sole asset is a 139-mile pipeline in South Texas of which HPL is also the operator. Mid Texas is accounted for under the equity method of accounting. HPL is subject to certain regulation with regard to rates and other matters by the Texas Railroad Commission. The formation of HPL and the transfer of ownership of HPC and HPL GP from other AEP subsidiaries to HPL were treated as a reorganization of entities under common control similar to a pooling of interest. Accordingly, the income and expense of HPC for all periods are included in the accompanying financial statements.
Consolidation Policy—The consolidated financial statements include the accounts of HPL and its subsidiaries. All intercompany transactions are eliminated.
Summary of Significant Accounting Policies
Use of Estimates—The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates.
Property, Plant and Equipment—Property, plant and equipment are stated at their fair market value at the date of acquisition plus the original cost of property acquired or constructed since acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts are deducted from accumulated depreciation, net of salvage. The costs of labor, materials and overheads incurred to operate and maintain plant and equipment are included in operating expenses. Assets are tested for impairments as required under SFAS 144 (see Note 2).
Interest Capitalization—Interest is capitalized during construction in accordance with Statement of Financial Accounting Standards (SFAS) No. 34, “Capitalization of Interest Costs.” The amount of interest capitalized was not material in 2004, 2003 and 2002.
F-276
Table of Contents
Index to Financial Statements
HPL CONSOLIDATION LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Depreciation and Amortization—Depreciation of plant and equipment is provided on a straight-line basis over their estimated useful lives and is calculated largely through the use of annual composite rates by functional class. The components and useful lives of property, plant, and equipment were as follows:
| December 31, |
||||||||
| 2004 |
2003 |
|||||||
| (In thousands) | ||||||||
| Land and Improvements |
$ | 2,295 | $ | 2,267 | ||||
| Buildings and Improvements (3 to 33 Years) |
6,898 | 6,447 | ||||||
| Pipelines and Equipment (19 to 50 Years) |
264,282 | 257,374 | ||||||
| Natural Gas Storage Facilities (30 to 35 Years) |
104,180 | 2,817 | ||||||
| Tanks and Other Equipment (15 to 36 Years) |
8,530 | 7,851 | ||||||
| Vehicles (4 Years) |
390 | 533 | ||||||
| Right of Way (30 Years) |
1,778 | 1,831 | ||||||
| Furniture and Fixtures (7 to 35 Years) |
1,128 | 1,107 | ||||||
| Linepack |
3,690 | 3,690 | ||||||
| Pad gas |
20,519 | 8,630 | ||||||
| Other (3 to 12 Years) |
6,931 | 6,484 | ||||||
| 420,621 | 299,031 | |||||||
| Less—Accumulated Depreciation |
(41,381 | ) | (32,491 | ) | ||||
| 379,240 | 266,540 | |||||||
| Plus—Construction work-in-process |
20,409 | 14,449 | ||||||
| Property, Plant and Equipment, Net |
$ | 399,649 | $ | 280,989 | ||||
Valuation of Non-Derivative Financial Instruments—The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments.
Cash and Cash Equivalents—Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Inventory—Inventories consist of natural gas in storage and in pipelines. During the year ended December 31, 2004, we purchased 45.4 Bcf ($228.2 million) of gas from AEP, which was being stored in the Bammel gas storage field. The gas inventory required to maintain company owned storage facility and pipeline minimum pressures is capitalized and classified as Property, Plant and Equipment. Gas inventory quantities in excess of the minimums, and gas held in third party facilities are carried at the lower of cost or market, utilizing the weighted average cost flow method.
Accounts Receivable—Customer accounts receivable primarily includes receivables from wholesale and retail gas customers, receivables from gas contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.
Materials and Supplies—Materials and Supplies inventories are carried at weighted average cost.
Exchange Gas Receivables and Payables—Exchange imbalance receivables from customers are valued at the lower of cost or market. Exchange imbalance payables to customers are valued at the higher of cost or market.
F-277
Table of Contents
Index to Financial Statements
HPL CONSOLIDATION LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Revenue Recognition
Domestic Gas Pipeline and Storage Activities
Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and that are accounted for using fair value accounting.
Marketing and Risk Management Activities
We engage in wholesale natural gas marketing and risk management activities. Effective in October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of gas under forward contracts at fixed and variable prices and the buying and selling of financial gas contracts, which include exchange traded futures and options, and over-the-counter options and swaps.
Accounting for Derivative Instruments
We use the fair value method of accounting for derivative contracts in accordance with SFAS 133. Unrealized gains and losses prior to settlement, resulting from revaluation of these contracts to fair value during the period, are recognized currently. When the derivative contracts are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed.
Certain derivative instruments are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the Consolidated Statement of Operations immediately. During 2004, we classified an immaterial amount into earnings as a result of hedge ineffectiveness related to our cash flow hedging strategies.
At December 31, 2004, we expect to reclassify approximately $35.7 million of net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months as the hedged transactions settle. The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ due to market price changes. As of December 31, 2004, four months is the maximum length of time that we are hedging, with SFAS 133 designated contracts, our exposure to variability in future cash flows for forecasted transactions.
The fair values of derivative instruments accounted for using fair value accounting or hedge accounting are based on exchange prices and broker quotes, when available. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, gas markets are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or
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favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.
We recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either “Price Risk Management Assets” or “Price Risk Management Liabilities” unless we have elected to treat the contracts as normal purchases or normal sales in accordance with the provisions of SFAS 133. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Operating Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled purchases of natural gas. The unrealized and realized gains and losses on these purchases are presented as Gas Purchases in the Consolidated Statements of Operations.
Material Contract Obligations not Reflected at Fair Value—HPL has entered into a number of contracts for services and gas purchase and sale contracts that are not reflected in the financial statements at fair value. The service contracts include the provision of storage, transportation, or gas processing services to customers for periods ranging from one month to three years. These transactions are recorded and reflected in revenues in the period in which the service is provided. Similarly, the subsidiaries Houston Pipe Line Company LP and AEP Gas Marketing, LP have contracts, generally with a term of one year or less, to purchase transportation services on third party pipelines. These costs are recorded and reflected in gas purchases in the period in which the service is utilized. A number of HPL’s gas purchase and sale contracts, which are generally for terms less than three years, primarily include purchases and sales of non-firm quantities of gas, which do not qualify for fair value accounting under SFAS 133, or contracts that are considered derivatives but are not fair valued as permitted by the normal purchase and sale exemption under SFAS 133. These transactions are recorded and reflected in revenues or cost of sales in the period in which the gas is delivered or received.
Maintenance Costs—Maintenance costs are expensed as incurred.
Nonoperating Gain—Nonoperating Gain includes gains on dispositions of property, and various other non-operating and miscellaneous income.
Income Taxes—For U.S. federal income tax purposes, we are considered a partnership. Therefore, we are not separately subject to U.S. federal tax on income, but are taxed in combination with AEP’s items of income and expense. Our subsidiaries are also generally partnerships not subject to U.S. federal income tax. We are party to a tax sharing agreement with AEP. The terms of the agreement require us to make payment to or receive refunds from AEP for taxes that are attributable to our operations, or any of our subsidiaries’ operations. We follow the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities, which will result in a future tax consequence. (See Note 8).
Excise Taxes—As an agent for a state or local government, we collect from customers certain excise taxes levied by the state or local government upon the customer. We do not recognize these taxes as revenue or expense.
Goodwill and Intangible Assets—When we acquire businesses we record the fair value of any acquired goodwill and other intangible assets. Purchased goodwill and intangible assets with indefinite lives are not amortized. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually. Intangible assets with finite lives are amortized over their respective estimated lives to their residual values.
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The policies described above became effective with our adoption of a new accounting standard for goodwill (SFAS 142). For all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years. Intangible assets with finite lives continue to be amortized over their respective estimated lives generally over 7 years.
The balance in Goodwill was $0 at December 31, 2004 and 2003. (See Note 5).
Acquired intangible assets subject to amortization include acquired miscellaneous intangibles with a gross carrying amount of $2.7 million and $2.4 million at December 31, 2004 and 2003. Accumulated Amortization was $1.2 million and $.9 million as of December 31, 2004 and 2003. Amortization Expense was $.3 million in 2004, 2003, and 2002. Estimated annual amortization expense is $.3 million for December 31, 2005, 2006, 2007, 2008, and 2009.
Comprehensive Income (Loss)—Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income has two components, net income and other comprehensive income.
Reclassification—Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.
2. New Accounting Pronouncements
SFAS 143 “Accounting for Asset Retirement Obligations”
In implementing SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred, we have identified, but not recognized, asset retirement obligation liabilities related to gas pipeline assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. The retirement obligation cannot be estimated for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements.
SFAS 144 “Accounting for the Impairment or Disposal of Long-lived Assets”
In August 2001, the FASB issued SFAS 144, “Accounting for the Impairment or Disposal of Long-lived Assets” which sets forth the accounting to recognize and measure an impairment loss. This standard replaced SFAS 121, “Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of.” We adopted SFAS 144 effective January 1, 2002. See Note 5 for discussion of impairments recognized in 2003.
SFAS 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
On April 30, 2003, the FASB issued Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative and the requirements for contracts to qualify for the normal purchase and sale exemption. SFAS 149 also amends certain other existing pronouncements. Effective July 1, 2003, we implemented SFAS 149 and the effect was not material to our results of operations, cash flows or financial condition.
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FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize liabilities related to issuing a guarantee, as well as additional disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the effect was not material to our results of operations, cash flows or financial condition. There are no guarantees which require disclosure in accordance with FIN 45.
EITF 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3”
In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus states that realized gains and losses on derivative contracts not “held for trading purposes” should be reported either on a net or gross basis based on the relevant facts and circumstances. Reclassification of prior year amounts was not required. The adoption of EITF 03-11 did not have a material impact on our results of operations, financial position or cash flows.
Future Accounting Changes
The FASB’s standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes.
3. Commitments and Contingencies
Construction and Other Commitments—We have substantial construction commitments to support our operations. Although not yet committed, we estimate aggregate construction expenditures for the period 2005 – 2007 are approximately $225.9 million.
HPL enters into contracts as part of their normal business activities. Most long-term contracts for purchase or sale of gas have pricing provisions referencing recognized market indexes. These contracts have force majeure provisions that would release HPL Companies from their obligation under certain conditions.
HPL’s long-term contracts for transportation, exchange, and processing of natural gas have varying term provisions, with some terms extending out until the year 2013. The majority of the contracts contain evergreen provisions, and many are currently already in their evergreen period. The contracts provide for periodic price adjustments and contain various clauses that would release HPL from their obligation under certain force majeure conditions.
HPL has contracted to sell certain quantities of processed gas liquids under long-term agreements providing for market-based rates in some instances through the year 2006. HPL could be released from their obligation under certain force majeure conditions.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP, including HPC, filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPC from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.
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Enron Bankruptcy—Bammel storage facility and HPL indemnification matters
In connection with the 2001 acquisition of HPC, AEP Energy Services Gas Holding Company (“AEPESGH”) entered into a prepaid arrangement under which AEP acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipeline pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years.
In January 2004, AEP filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which AEP acquired title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million, which increased HPL’s property, plant and equipment account, of which $11.9 million was allocated to Pad Gas and the remainder to Natural Gas Storage Facilities. AEP and Enron agreed to release each other from all claims associated with the Bammel facility, including AEPESGH’s indemnity claims. The settlement received Bankruptcy Court approval in September 2004 and closed in November 2004. The parties’ respective trading claims and Bank of America’s (“BOA” or “BofA”) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement.
Enron Bankruptcy—Right to use of cushion gas agreements
In connection with the 2001 acquisition of HPC, AEPESGH also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (including the 10.5 BCF described in the preceding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of the acquisition of HPC, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of the acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.
After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in state court in Texas seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.
In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPC, that BOA directly benefited from the sale of HPC and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have
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known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA has objected to the Magistrate Judge’s decision and the matter is now before the District Judge.
In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. AEP has objected to Enron’s attempted rejection of these agreements.
On January 26, 2005, AEP sold a 98% limited partner interest in HPL. AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from the BOA litigation. (See Note 13).
Environmental Regulations—HPL is subject to extensive federal, state and local laws and regulations concerning the release of materials into the environment, and which require expenditures for remediation at various sites.
HPL has 10 known environmental remediation sites. HPL has accrued liabilities of $3.3 million and $4.0 million for the costs as of December 31, 2004 and 2003. Management feels that adequate reserves have been made for any potential future costs related to these sites. Other than the identified potential clean up sites, HPL believes that its operations and facilities are in general compliance with applicable environmental regulations.
Litigation and Other Contingencies
We are party to various legal proceedings. For each of these matters, we evaluate the merits of the case, our exposure to the matter, and possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we make the necessary accruals. As new information becomes available, our estimates may change. Following is a discussion of several of our more significant matters.
*False Claims Act Litigation brought by Jack J. Grynberg on behalf of the United States of America, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wyo.) (“Grynberg II”). Generally, these complaints allege an industry-wide conspiracy to under-report the heating value as well as the volumes of natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. Grynberg also alleges that transactions between the defendants and their affiliates have caused royalty underpayments. These matters have been consolidated for pretrial purposes. One HPL Consolidation LP entity, Houston Pipe Line Company LP is named as defendant.
In May 2001, the court denied the defendants’ motions to dismiss.
In July 2000, the U.S. government moved to dismiss some of the so-called “valuation” claims in all the consolidated Grynberg II cases, including those against HPL. The government sought dismissal of two categories of allegations: one deals with the alleged deduction of costs in excess of the “reasonable actual costs incurred” for transportation services; the other concerns alleged sales to affiliates. In October 2002, the Court granted the government’s motion to dismiss. The Court based its ruling on the statutory authority of the United States to seek
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dismissal of a False Claims Act case when that dismissal would serve a legitimate government purpose. The Court essentially ruled that Grynberg’s pursuit of his valuation claims would interfere with the government’s ability to pursue royalty valuation claims in another False Claims Act case filed by a different relator. Grynberg was ordered to file amended complaints encompassing his remaining mis-measurement claims, and Grynberg did so. Grynberg’s attempt to obtain interlocutory review was unsuccessful.
On June 4, 2002, the defendants (including HPC) filed various motions to dismiss the case, arguing that the court does not have subject matter jurisdiction under the public disclosure bar and the voluntary disclosure provisions of the False Claims Act. Briefing of those motions is complete, and oral argument is scheduled for March 17-18, 2005.
The defendants believe the lawsuit is not meritorious, have successfully urged the U.S. not to intervene in the cases, and are contesting the claims vigorously.
*Bank of America, N.A., as Administrative Agent, and as Representative of Wilmington Trust Company, Trustee of The Bammel Gas Trust v. Houston Pipe Line Company LP; Cause No. 2002-36488 in the District Court of Harris County, Texas, 280th Judicial District. This matter was filed in July 2002. Through the lawsuit, BofA sought declaratory relief from a Texas state district court regarding its rights in “up to 55 Bcf” of “Storage Gas” allegedly stored in the Bammel Storage Facility operated by HPL. BofA claimed to seek this relief as the alleged “Administrative Agent” for a group of lenders to entities related to Enron, as well as the alleged “Representative” of the Bammel Gas Trust, the entity that BofA claims owns the “Storage Gas” at issue. BofA claims that through a financing transaction involving Enron Corp. in 1997—which was restructured at the time AEP, through its wholly owned subsidiary AEPESGH acquired HPC from Enron in 2001—it holds, as “Administrative Agent” for a group of lenders, a security interest in “up to 55 Bcf” of “Storage Gas” located in the Bammel Storage Facility. BofA initially claimed that as “Administrative Agent” it had the right under the security interest and other financing documents to foreclose on the “Storage Gas,” both on behalf of the lender group and as “Representative” of the Bammel Gas Trust. BofA also sought its attorneys’ fees and expenses and court costs.
For its response, HPC denied BofA’s claims and also asserted various affirmative defenses to the claims for declaratory relief by BofA. HPC also filed counterclaims against BofA, on grounds that the efforts by BofA to execute on the claimed security interest breached contractual obligations entered into by BofA and the Bammel Gas Trust at the time of the 2001 acquisition. The contractual rights sought to be enforced by HPC include a contractual right, consented to by BofA, to use any gas against which BofA might assert a security interest for operation of the Bammel Storage Facility. HPC sought a recovery of actual damages, including but not limited to attorneys’ fees and expenses, on its counterclaims.
Both sides filed motions for summary judgment as to various claims. On December 9, 2003, the court entered a final judgment dismissing HPC’s counterclaims with prejudice and granting BofA’s requests for declaratory judgment in part. The trial court entered declarations that (1) HPC is estopped to deny that the Trustee of the Bammel Gas Trust is the owner of the “Storage Gas”; (2) BofA has a security interest that is, “as against HPC,” a valid and first priority security interest in the “Storage Gas”; (3) a “Guaranty Default” has occurred under the financing, through Enron-related bankruptcy filings; (4) and any rights of HPC’s to use the “Storage Gas” under various 2001 agreements is “subject to” BofA’s claimed rights in “Storage Gas.” BofA nonsuited its claims for declaratory relief relating to enforcement of its claimed interests in the “Storage Gas.” HPC believes that a significant number of issues were left unresolved by the trial court’s judgment, including but
*AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from this litigation.
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not limited to the issue of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach. HPC has taken an appeal from the trial court’s judgment, which is pending. HPC filed its appellant’s brief on February 14, 2005. BofA’s appellee’s brief is due March 16, 2005.
During the pendency of the appeal, on January 7, 2004, BofA filed Cause No. 2004-00384 against HPC, alleging that HPC breached contractual obligations with BofA by allegedly withdrawing, or permitting the depletion of, the aggregate quantity of recoverable natural gas in the Bammel Storage Reservoir to less than 40 Bcf. BofA sought damages as well as declaratory and injunctive relief against HPC relating to these agreements.
On January 30, 2004, HPC filed an answer generally denying BofA’s claims. HPC then removed the state court action to federal court on February 2, 2004. While pending in federal court, the case was styled as C.A. No. H-04-0405; Bank of America, N.A., As Administrative Agent, and As Representative of The Bank of New York, Trustee of the Bammel Gas Trust v. Houston Pipe Line Company LP; In the United States District Court for the Southern District of Texas, Houston Division. The case was remanded back to state court on May 24, 2004. BofA then amended its petition to assert additional claims for the immediate possession of 55 Bcf of natural gas stored in the Bammel Storage Facility.
On July 27, 2004, BofA filed an application for and obtained an ex parte writ of sequestration regarding natural gas allegedly stored in the Bammel Storage Facility. HPC moved to dissolve the writ. After a full-day evidentiary hearing held on August 6, 2004, the district court indicated that it intended to vacate or modify its July 27, 2004 order pending resolution of HPC’s appeal of the final judgment and the ongoing federal declaratory and bankruptcy litigation described below. On August 11, 2004, BofA nonsuited Cause No. 2004-00384 without prejudice. On August 13, 2004, the court entered an order of dismissal in which, in addition to dismissing the lawsuit, vacated the July 27, 2004 order and dissolved the writ of sequestration.
On October 6, 2004, BofA filed a “petition for further relief to enforce declaratory judgment” with the trial court in Cause No. 2002-36488. By this filing, BofA sought to enforce its claimed rights under the final judgment through, among other things, the sequestration of an amount of gas sufficient to protect its claimed rights under the final judgment and/or an order allowing BofA to take immediate possession of 55 Bcf of gas located in the Bammel Storage Facility. Following this filing, Cause No. 2002-36488 was administratively transferred from the 280th District Court of Harris County (where the case had been pending and the final judgment had been entered) to the 133rd District Court, in which BofA had initiated the writ of sequestration proceedings in Cause No. 2004-00384. On December 17, 2004, BofA filed an “application for further relief to enforce final judgment,” seeking much of the same relief previously sought by the earlier-filed application for writ of sequestration in Cause No. 2004-00384 and “petition for further relief” in Cause No. 2002-36488, including a request for an order authorizing BofA to take possession of 55 Bcf of “Storage Gas” allegedly located in the Bammel Storage Facility. A hearing on BofA’s application is currently set for March 14, 2005.
HPC intends to vigorously prosecute its appeal of the declaratory judgment and to contest BofA’s latest application for further relief relating to that judgment.
Since the filing of the foregoing action, AEP has filed a related suit styled AEP Energy Services Gas Holding Company, Houston Pipe Line Company LP, and HPL Resources Company LP v. Bank of America, N.A., as “Administrative Agent,” as “Master Swap Counterparty,” as “Secured Party,” and as “Purchaser”; and The Bank of New York, as Trustee of the Bammel Gas Trust; Civil Action No. H-03-4973 in the United States District Court for the Southern District of Texas, Houston Division. On October 31, 2003, AEPESGH filed suit against Bank of America, N.A. (“BofA”) for breach of contract and negligent misrepresentation in connection with the
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acquisition by AEPESGH of HPC from Enron Corp. in 2001. AEPESGH alleges that BofA breached contractual covenants and committed negligent misrepresentation in connection with its representations to AEPESGH relating to Enron’s financial condition. On January 8, 2004, AEPESGH, along with HPC and HPL Resources Company LP (“HPLR”) (the last two of which are HPL Consolidation LP entities), amended and supplemented the complaint to include additional claims, including fraud claims by AEPESGH against BofA and requests for declaratory relief related to issues left unresolved by the trial court in Harris County, including the issues of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach.
In addition to the declaratory relief and attorneys’ fees and costs sought by all plaintiffs, AEPESGH seeks to recover actual and exemplary damages from BofA.
BofA has filed a motion to dismiss the case for lack of subject matter jurisdiction and on grounds of collateral estoppel and res judicata. AEPESGH, along with the other Plaintiffs, filed its opposition to this motion. The motion was referred to a United States Magistrate Judge. On September 14, 2004, the Magistrate Judge issued an order recommending that BofA’s motion to dismiss be denied in its entirety. The magistrate judge also ordered that the Plaintiffs’ declaratory claims should be severed and transferred to the United States District Court for the Southern District of New York.
BofA has filed objections to the Magistrate Judge’s recommendations. AEPESGH, along with the other Plaintiffs, timely filed responses to these objections. The district court has not yet ruled on these objections.
Plaintiffs initiated discovery in the case. On April 22, 2004, the Magistrate Judge made an oral ruling staying discovery pending its determination of Defendants’ motion to dismiss. Plaintiffs filed a motion to lift the stay on discovery on October 22, 2004. The motion remains pending.
Trial is currently set for December 2005. Plaintiffs intend to vigorously pursue their claims.
*In addition to the previously described federal lawsuit, AEP has filed an adversary proceeding in the Enron Corp. bankruptcy styled Houston Pipe Line Company LP, HPL Resources Company LP, and AEP Energy Services Gas Holding Company v. Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., Individually and as Administrative Agent; Adversary No. 03-93372, as filed in Case No. 01-16045 (AJG) in the United States Bankruptcy Court for the Southern District of New York. On November 21, 2003, HPC, HPL Resources Company LP, and AEPESGH (“Plaintiffs”) filed an adversary proceeding against Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., individually and as Administrative Agent (“Defendants”). Plaintiffs sought a declaration of their rights with respect to the documents executed in connection with the 2001 acquisition of HPC and HPL Resources Company LP by AEPESGH.
Plaintiffs seek declarations, among others, that various agreements under which Plaintiffs use and operate the Bammel Storage Facility and its appurtenances, including pipelines and cushion gas in the facility (the “Bammel Storage Assets”), are not subject to rejection under bankruptcy law principles; and that even if these agreements could be rejected, Plaintiffs would be entitled to maintain possession of and use these assets for the contractual period provided for under these agreements.
On January 29, 2003, following the filing of the amended and supplemental complaint in the matter described above, Plaintiffs amended their complaint in the adversary proceeding to remove claims made in that proceeding against Bank of America, N.A.
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Discovery in the adversary proceeding has commenced, and absent a settlement Plaintiffs intend to pursue their claims vigorously as against the Enron-related parties to the adversary proceeding.
*John and Heather Maher, et al, and all others similarly situated v. CenterPoint Energy, Inc. d/b/a Reliant Energy, Incorporated, et al.; Cause No. 38075, in the 23rd Judicial district Court of Wharton County, Texas. This lawsuit was filed in October 2002 on behalf of two residents of Wharton County, Texas against a number of entities related to CenterPoint Energy, Inc. and Kinder Morgan Inc. Plaintiffs have also named HPL Consolidation LP subsidiaries HPC, its general partner, HPL GP, LLC and AEP Gas Marketing LP (now HPL Gas Marketing LP) as defendants. Plaintiffs allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas. When the lawsuit was initiated, Plaintiffs also sought to certify a class and to be named as the representatives of the class.
The defendants, including the HPL Consolidation LP subsidiaries, filed motions to dismiss the case on grounds, among others, that primary jurisdiction over claims raised by Plaintiffs with respect to rates charged to residential consumers of natural gas resided in the Texas Railroad Commission. The parties commenced to take discovery related to threshold issues of subject matter jurisdiction, venue, and the class certification request.
On February 4, 2005, Plaintiffs filed an amended petition in which they removed all class action allegations. Plaintiffs added AEP Energy Services, Inc. as a defendant, as well as eight additional defendants affiliated with CenterPoint or Kinder Morgan. Plaintiffs continue to allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and the Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas.
On February 11, 2005, the CenterPoint Defendants removed the action to federal court in the United States District Court for the Southern District of Texas, Houston Division on the basis of a federal question related to Plaintiffs’ newly asserted allegations against CenterPoint Energy Gas Transmission Company, an interstate natural gas transportation and storage services company. The HPL Consolidation LP subsidiaries, AEP Energy Services, Inc. (“AEPES”), a wholly owned subsidiary of AEP, and the Kinder Morgan Defendants consented to the removal. A scheduling conference is scheduled for June 7, 2005 in the federal court.
Plaintiffs have not specified the amount of their damage claims, but seek injunctive relief, actual damages, exemplary damages, statutory damages, civil penalties, and attorneys’ fees and expenses. The HPL Consolidation LP subsidiaries, AEP Energy Services, Inc. and other defendants, have denied Plaintiffs’ claims and continue to assert that Plaintiffs’ attempted challenges to the rates charged by a regulated natural gas utility are subject to the jurisdiction of the Texas Railroad Commission.
The HPL Consolidation LP subsidiaries and AEP Energy Services, Inc. will continue to vigorously contest the Plaintiffs’ claims.
*Weldon Johnson and Guy W. Sparks, individually and as representatives of others similarly situated v. CenterPoint Energy, Inc., et al.; Cause No. 04-327-02, in the Circuit Court of Miller County, Arkansas. On October 8, 2004, Plaintiffs filed this lawsuit on behalf of two individuals, one a resident of Arkansas and the other a resident of Texas, seeking to certify a nationwide class action against the same HPL Consolidation LP subsidiaries named in the Maher case and a number of entities related to CenterPoint Energy, Inc. (“CenterPoint”) and Kinder Morgan Inc. (“Kinder Morgan”). Plaintiffs allege fraud and civil conspiracy claims against all of the defendants and seek an unspecified amount in damages for alleged unjust enrichment, actual damages, punitive and exemplary damages, attorneys’ fees, and interest.
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On November 18, 2004, the CenterPoint Defendants removed the action to the United States District Court in the Western District of Arkansas, Texarkana Division on the basis of a federal question. The HPL and Kinder Morgan Defendants consented to the removal. On January 26, 2005, Plaintiffs filed a motion to remand. On February 10, 2005, the CenterPoint Defendants filed a response to the motion to remand.
On December 17, 2004, the HPL Consolidation LP subsidiaries Defendants filed a motion to dismiss asserting, among other things, that (1) the Arkansas Courts lack personal jurisdiction over each of them and (2) the Plaintiffs have failed to assert claims against any of the HPL subsidiaries upon which relief can be granted. The CenterPoint Defendants and Kinder Morgan Defendants have also filed motions to dismiss.
The Plaintiffs have not filed responses to the motions to dismiss. The court has indicated it will decide the remand issues before it decides the dismissal issues. At present, the motion to remand and the motions to dismiss are pending before the court.
The HPL Consolidation LP subsidiaries will continue to vigorously contest the Plaintiffs’ claims.
*Railroad Commission of Texas Oil and Gas Docket No. 02-0231838; Enforcement Action Against HPL Resources Company (Operator No. 407240) for Violations of Statewide Rules on the Magnolia City Plant Site (No. 04-0359), Nueces County, Texas. This case involves alleged soil and groundwater contamination at the Magnolia City Plant Site (the “Mag City Site”) located in Nueces County, Texas. Historically, there were two plants operated at the site: the Dean Plant and the Magnolia City Plant. The Dean Plant processed gas from 1953 until 1975, when the plant was permanently shut down. The Dean Plant was operated by a number of Tenneco and Tennessee Gas-related entities whose successors in interest include El Paso Natural Gas (“El Paso”) and Tennessee Gas Pipeline (“TGP”). Based on available facts, its does not appear that HPLR ever owned, operated or had any affiliation with the Dean Plant. The Magnolia City Plant was built in 1985 and was shut down in 1996. The Railroad Commission of Texas alleges that HPLR filed Form R-3s (entitled “Monthly Report for Gas Processing Plants”) for the Magnolia City Plant and is thus liable (or presumed liable) for the Mag City Site contamination.
Citing §91.101 of the Texas Natural Resources Code, the Commission filed a complaint alleging that HPLR “caused or allowed” pollution and discharged oil and gas wastes without a permit at the Magnolia City Plant in violation of Commission Rules 8(b) and 8(d)(1). The primary constituents of concern (“COCs”) are hydrocarbons, volatile organic compounds (“VOCs”), chloroform, chromium and chlorides. There is possible offsite contamination. However, the extent of the contamination has not been fully delineated.
Under the terms of a April 2000 Settlement Agreement, Indemnity and Release (“Indemnity”), HPC indemnified TGP and El Paso for all claims related to TGP’s or El Paso’s “environmental obligations” at the Mag City Site excepting those claims defined as “Boundary Area Claims.” The term “Boundary Area Claims” is defined in the Indemnity as “subsurface contamination which has migrated from the Plant site from the general location of the former blowdown pit located near the fence line of the northeast boundary of the Plant property.” Under the terms of this agreement, HPC (or its parent company at that time) was paid $205,000.
HPC and HPLR answered the Commission’s complaint. Some limited discovery was conducted. The Commission made HPC/HPLR a settlement offer and the parties have entered into settlement negotiations. In the meantime, the Commission contacted El Paso as a potentially responsible party. El Paso and AEP plan to meet to discuss the terms and scope of the Indemnity, the site background, the scope of each party’s potential liability and how best to proceed.
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*Tuleta Plant Site Investigation (former gas plant located in Bee County, Texas). This case involves alleged soil and groundwater contamination at the Tuleta Gas Plant Site (“Tuleta”). The Tuleta Plant was a natural gas liquids processing plant that was first built in the 1940s. The plant employed a lean oil liquid extraction process. Natural gas processing operations ceased on or before July 1986. However, the site was still used for separation, compression, dehydration and/or condensate storage operations into the 1990s. HPC conducted operations at the site from January 1987 until October 1990. It appears that HPC’s operations at the site consisted solely of natural gas separation, dehydration and compression. Several entities operated the plant prior to January 1987. The successors in interest to those prior plant operators that are still solvent include: H.B. Zachry; EOG Resources, Inc.; and OneOK Bushton Processing, Inc. (“Prior Plant Operators”). Other parties with operations on site include Valero and Wagner Oil. The COCs at this site include lean oil, condensate and glycol. Extensive historic site investigations suggest there were possibly multiple releases from multiple sources (both on-site and off-site). However, the site has not been fully delineated at this time. Further, it is not clear whether HPC has any historic contractual obligations to remediate environmental conditions at this site. None have been identified to date.
There is no current litigation or enforcement action concerning environmental conditions at this site. HPC was originally contacted by the Commission and asked to assume full responsibility for the contamination alleged at the site. However, since that time, the Commission has asked the Prior Plant Operators to share in the site remediation. HPC and the Prior Plant Operators retained an environmental consultant and voluntarily conducted a Baseline Study that reviewed all prior site investigative work. This Baseline Study was submitted to the Commission on February 11, 2005. In the meantime, the Commission sent letters to Valero and Wagner Oil requesting that they attend a future meeting with the Commission, HPC and the Prior Plant Operators. Additional negotiations among the various parties and the Commission are anticipated.
City of Victoria v. Houston Pipe Line Company, et al.; Cause No. 03-6-59,833-C, in the 267th Judicial District Court of Victoria County, Texas. The City of Victoria (“Victoria”) filed suit against Houston Pipe Line Company, Houston Pipe Line Company, L.L.C., and Houston Pipe Line Company, L.P. (the HPL subsidiaries) alleging that HPC owes Victoria taxes for use of its streets, alleys, rights-of-way, and/or public property in transporting and selling gas. Victoria relies on city ordinance 14-116 for its assessment of the taxes. Ordinance 14-116 was passed on July 7, 1941, and, in summary, states that any entity owning, operating, managing or controlling any gas, electric light, or electric power plant within Victoria city limits and used for local sale and distribution using streets, alleys and/or public ways must file revenue reports with Victoria and pay Victoria two percent of gross receipts from the sale of such gas, electric lights or electric power derived from consumers. Based on these factual allegations, Victoria has alleged a violation of ordinance 14-116 and negligence per se.
This case is in the early stages of discovery. Written discovery is currently being exchanged.
In response to discovery requests Victoria has produced documents that it claims were provided to Victoria by FERC and PUC. The documents appear to be a record of all gas sales from HPC and Central Power & Light (“CPL”), a wholly owned subsidiary of AEP, in Victoria during the period of May 1976 to December 2002. The total gross sales listed is $219,607,177.83. Victoria has claimed that the amount owed in taxes is 2% of gross sales. Thus, Victoria is claiming that $4,392,143.56 in taxes is owed by HPC to Victoria. The gross sales number provided by Victoria has not yet been verified by HPC.
HPL anticipates filing a motion for summary judgment based on the construction of the ordinance. HPL will contend that a plain reading of the ordinance shows that the ordinance is not applicable to HPL.
City of Corpus Christi, Texas v. Air Liquide America, L.P., et al., Cause No. 04-06556-A, In the District Court of Nueces County. On November 17, 2004, the City of Corpus Christi (“Corpus”) filed, but has not yet served, the above-referenced lawsuit, which names approximately forty defendants, including HPC. The City
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primarily seeks to obtain a declaration of the validity of City Ordinance No. 026023, which requires that defendants obtain a license from Corpus or equivalent authorization for their continued use of Corpus’s rights-of-way and city-owned properties (the “Ordinance”). The Ordinance requires, in exchange for permission to use certain affected city rights-of-way and city-owned property, that each defendant remit to Corpus “fair compensation”, as set forth in the Ordinance. Generally, that “fair compensation” includes a charge of $500 per crossing and $1.25 per foot for laying alongside public rights-of-way. Additionally, Corpus alleges trespass, purpesture (an alleged encroachment upon public rights belonging to and/or controlled by Corpus) and unjust enrichment.
Prior to filing suit, Corpus had by written letter revoked the revocable easement agreements held by HPC and other defendants.
HPC, as a member of the Texas Energy Coalition (“TEC”), has engaged in settlement negotiations with Corpus, which are continuing. Under those proposals, the fees, which pipelines such as HPC would pay are limited to an approximation of a reasonable regulatory fee.
If settlement discussions fail and HPC is served, HPC intends to vigorously defend this lawsuit.
While the outcomes of the matters discussed above cannot be predicted with certainty, based on information known to date and considering reserves established as of December 31, 2004, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results, or cash flow.
4. Equity Investment in Nonconsolidated Subsidiary
HPL owns a 50% equity interest in Mid Texas Pipeline Company.
The 2004, 2003 and 2002 equity loss from the Mid Texas investment is $683 thousand, $668 thousand and $249 thousand, respectively. The following amounts, which are not consolidated into our financial statements represent summarized financial information of Mid Texas:
| Year Ended December 31, | ||||||
| 2004 |
2003 | |||||
| (In thousands) | ||||||
| Assets |
||||||
| Property, Plant and Equipment (Net) |
$ | 65,977 | $ | 67,281 | ||
| Current Assets |
925 | 959 | ||||
| TOTAL |
$ | 66,902 | $ | 68,240 | ||
| Capitalization And Liabilities |
||||||
| Common Shareholders’ Equity |
$ | 66,070 | $ | 67,437 | ||
| Current Liabilities |
832 | 803 | ||||
| TOTAL CAPITALIZATION AND LIABILITIES |
$ | 66,902 | $ | 68,240 | ||
| Year Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| (In thousands) | |||||||||
| Operations Statement Data |
|||||||||
| Operating Loss |
$ | 2,469 | $ | 2,473 | $ | 2,296 | |||
| Net Loss |
1,366 | 1,336 | 499 | ||||||
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We own and operate natural gas gathering, transportation and storage operations in Texas. During the fourth quarter of 2003, based on a probability-weighted after-tax cash flow analysis of our fair value, we recorded an impairment of $300 million pre-tax ($218 million after-tax), with $150 million pre-tax related to the entire balance of goodwill, reflecting management’s decision not to operate as a major trading hub. The cash flow analysis, among other things, used management’s estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters (see Note 3) and an after-tax risk free discount rate of 3.3% over the remaining life of the assets.
We participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, we participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees in the U.S. We implemented FSP FAS 106-2 in the second quarter of 2004, retroactive to the first quarter of 2004 (see “FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” section of Note 2). The Medicare subsidy reduced the FAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service. Our reduction in the net periodic postretirement cost for 2004 was $150,000.
Pension and Other Postretirement Plans’ Assets:
The asset allocations for AEP’s pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category, are as follows:
| Target 2005 |
Percentage of Plan Assets at Year End | |||||
| 2004 |
2003 | |||||
| (In percentages) | ||||||
| Asset Category |
||||||
| Equity Securities |
70 | 68 | 71 | |||
| Debt Securities |
28 | 25 | 27 | |||
| Cash and Cash Equivalents |
2 | 7 | 2 | |||
| Total |
100 | 100 | 100 | |||
The asset allocations for AEP’s other postretirement benefit plans at the end of 2004 and 2003, and target allocation for 2005, by asset category, are as follows:
| Target 2005 |
Percentage of Plan Assets at Year End | |||||
| 2004 |
2003 | |||||
| (In percentages) | ||||||
| Asset Category |
||||||
| Equity Securities |
70 | 70 | 61 | |||
| Debt Securities |
28 | 28 | 36 | |||
| Other |
2 | 2 | 3 | |||
| Total |
100 | 100 | 100 | |||
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AEP’s investment strategy for their employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation when considered appropriate. Because of a discretionary contribution at the end of 2004, the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2005.
AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
AEP’s combined pension funds are underfunded in total (plan assets are less than projected benefit obligations) at December 31, 2004.
AEP made an additional discretionary contribution in the fourth quarter of 2004 and intends to make additional discretionary contributions in 2005 to meet its goal of fully funding all qualified pension plans by the end of 2005.
The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:
| Pension Plans |
Other Postretirement Benefit Plans | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| (In percentages) | ||||||||
| Discount Rate |
5.50 | 6.25 | 5.80 | 6.25 | ||||
| Rate of Compensation Increase |
3.70 | 3.70 | N/A | N/A | ||||
The method used to determine the discount rate that AEP utilizes for determining future benefit obligations was revised in 2004. Historically, it has been based on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, AEP changed to a duration based method where a hypothetical portfolio of high quality corporate bonds was constructed with a duration similar to the duration of the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for pension plans and 5.80% for other postretirement benefit plans.
The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.
The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ expense for accounting purposes and is provided for in agreements with state regulatory authorities.
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The Company participates in the AEP system qualified pension plan, a defined benefit plan that covers all employees. Net periodic benefit cost for the years ended December 31, 2004 and 2003 were $1,102,000 and $965,000, respectively.
Postretirement benefits other than pensions are provided for retired employees for medical and death benefits under an AEP System plan. The annual accrued costs were $816,000 and $1,186,000 in 2004 and 2003, respectively.
The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:
| Pension Plans |
Other Postretirement Benefit Plans | |||||||||||
| 2004 |
2003 |
2002 |
2004 |
2003 |
2002 | |||||||
| (In percentages) | ||||||||||||
| Discount Rate |
6.25 | 6.75 | 7.25 | 6.25 | 6.75 | 7.25 | ||||||
| Expected Return on Plan Assets |
8.75 | 9.00 | 9.00 | 8.35 | 8.75 | 8.75 | ||||||
| Rate of Compensation Increase |
3.70 | 3.70 | 3.70 | N/A | N/A | N/A | ||||||
The expected return on plan assets for 2004 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as unrelated business income taxes) was reduced to 8.35%.
A defined contribution employee savings plan required that the Company make contributions to the plan totaling $643,000 and $640,000 in 2004 and 2003.
In 2002, there were no separately identifiable costs related to associated net pension benefit costs, postretirement benefit costs or savings plan contributions as theses costs were included in an overall fringe benefit charge to HPL. AEP does not allocate pension liabilities to its subsidiaries, including HPL.
7. Derivatives, Hedging and Financial Instruments
Derivatives and Hedging
We apply SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Derivatives include interest rate swaps, commodity swaps, options and futures contracts and certain physical gas purchases and sales contracts.
SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value unless the contracts qualify for normal purchase or normal sale treatment. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies, and has been designated, as part of a hedging relationship. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. These contracts are not reported at fair value, as otherwise required by SFAS 133.
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative
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instrument as a component of Accumulated Other Comprehensive Income and subsequently reclassify it to Revenues or Gas Purchases in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change.
Cash Flow Hedging Strategies
We enter into forward and swap transactions for the purchase and sale of natural gas to manage the variable price risk related to the forecasted purchases and sales of natural gas. We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future sales. We do not hedge all variable price risk exposure related to the forecasted purchases and sales of natural gas.
The following table represents the activity in Accumulated Other Comprehensive Income (Loss) (“AOCI”) for derivative contracts that qualify as cash flow hedges at December 31, 2004:
| Amount |
||||
| (In thousands) | ||||
| Beginning Balance, December 31, 2001 |
$ | — | ||
| Changes in fair value |
— | |||
| Reclasses from AOCI to net earnings |
— | |||
| Balance December 31, 2002 |
— | |||
| Changes in fair value |
(281 | ) | ||
| Reclasses from AOCI to net earnings |
— | |||
| Balance December 31, 2003 |
(281 | ) | ||
| Changes in fair value |
35,683 | |||
| Reclasses from AOCI to net earnings |
281 | |||
| Ending Balance, December 31, 2004 |
$ | 35,683 | ||
The details of income tax (benefit) expenses applicable to continuing operations are as follows:
| Year Ended December 31, | ||||||||||
| 2004 |
2003 |
2002 | ||||||||
| (In thousands) | ||||||||||
| FEDERAL |
||||||||||
| Current |
$ | 18,296 | $ | (484 | ) | $ | 21,285 | |||
| Deferred |
4,398 | (81,111 | ) | 2,319 | ||||||
| Total Income Tax as Reported |
$ | 22,694 | $ | (81,595 | ) | $ | 23,604 | |||
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The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported.
| Year Ended December 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| (In thousands) | ||||||||||||
| Net Income (Loss) |
$ | 44,026 | $ | (216,571 | ) | $ | 43,457 | |||||
| Income Tax Expense (Credit) |
22,694 | (81,595 | ) | 23,604 | ||||||||
| Pre-Tax Income (Loss) |
$ | 66,720 | $ | (298,166 | ) | $ | 67,061 | |||||
| Income Tax on Pre-Tax Income at Statutory Rate (35%) |
23,352 | (104,358 | ) | 23,471 | ||||||||
| Increase (Decrease) in Income Tax Resulting from the Following Items: |
||||||||||||
| Impairment of Goodwill (nondeductible portion) |
— | 23,021 | — | |||||||||
| Other |
(658 | ) | (258 | ) | 133 | |||||||
| Total Income Taxes as Reported |
$ | 22,694 | $ | (81,595 | ) | $ | 23,604 | |||||
| Effective Income Tax Rate |
34.01 | % | 27.37 | % | 35.20 | % | ||||||
The following table shows the elements of the net deferred tax asset and the significant temporary differences:
| Year Ended December 31, |
||||||||
| 2004 |
2003 |
|||||||
| (In thousands) | ||||||||
| Property Related Temporary Differences |
$ | (21,018 | ) | $ | (13,412 | ) | ||
| Impaired Assets |
52,957 | 51,910 | ||||||
| Provisions for Losses |
8,398 | 8,398 | ||||||
| Tax Basis Goodwill |
21,931 | 25,370 | ||||||
| Price-Risk Management Assets (Net) |
13,587 | 9,417 | ||||||
| Other Comprehensive Income (Loss) Cash Flow Hedges |
(19,214 | ) | 151 | |||||
| Prepaid Leases |
37,238 | 35,888 | ||||||
| All Other (Net) |
4,521 | 4,442 | ||||||
| Net Deferred Tax Assets |
$ | 98,400 | $ | 122,164 | ||||
We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.
The IRS and other taxing authorities routinely examine our returns. Returns for the years 2001 through 2003 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.
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Leases include property, plant and equipment and gas pipeline rights of way. Leases of property, plant and equipment are for periods up to 10 years and require payments of related property taxes, maintenance and operating costs. Leases of gas pipeline rights of way range from one year to perpetuity. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Property, plant, and equipment under capital leases at December 31, 2004 are predominantly general plant equipment and at December 31, 2003 are predominately the assets leased from BAM Lease Company. The assets leased from BAM Lease Company were purchased by HPL in November 2004 as described in Note 3. The $120.1 million value for leased assets became part of owned pipeline and equipment with this purchase. The BAM Lease Company lease payments were prepaid at the acquisition of HPC, therefore, there are no future payment obligations for the remainder of the primary lease term.
Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:
| Year Ended December 31, | ||||||
| 2004 |
2003 | |||||
| (In thousands) | ||||||
| Property, Plant and Equipment Under Capital Leases |
||||||
| Production and Other |
$ | 28 | $ | 120,094 | ||
| Total Property, Plant and Equipment |
28 | 120,094 | ||||
| Accumulated Amortization |
3 | 15,097 | ||||
| Net Property, Plant and Equipment Under Capital Leases |
$ | 25 | $ | 104,997 | ||
| Obligations Under Capital Leases |
||||||
| Noncurrent Liability |
$ | 16 | $ | 3 | ||
| Liability |
9 | 1 | ||||
| Total Obligations Under Capital Leases |
$ | 25 | $ | 4 | ||
Lease rentals for operating and capital leases were as follows:
| Year Ended December 31, | ||||||
| 2004 |
2003 | |||||
| (In thousands) | ||||||
| Lease Payments on Operating Leases |
$ | 1,900 | $ | 1,287 | ||
| Amortization of Capital Leases |
3 | 6,923 | ||||
| Interest on Capital Leases |
3 | — | ||||
| Total Lease Rental Cost |
$ | 1,906 | $ | 8,210 | ||
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Future minimum lease payments consisted of the following at December 31, 2004:
| (In thousands) | |||
| Capital Leases |
|||
| 2005 |
$ | 9 | |
| 2006 |
8 | ||
| 2007 |
7 | ||
| 2008 |
2 | ||
| 2009 |
— | ||
| Later Years |
— | ||
| Total Future Minimum Lease Payments |
26 | ||
| Less Estimated Interest Element |
1 | ||
| Estimated Present Value of Future Minimum Lease Payments |
$ | 25 | |
| Noncancelable Operating Leases |
|||
| 2005 |
$ | 337 | |
| 2006 |
275 | ||
| 2007 |
209 | ||
| 2008 |
131 | ||
| 2009 |
83 | ||
| Later Years |
102 | ||
| Total Future Minimum Lease Payments |
$ | 1,137 | |
10. Concentration Of Credit Risks
At December 31, 2004, two non-affiliated customers represented more than 10% of related total revenues or accounts receivable. At December 31, 2003, one non-affiliated customer represented more than 10% of the related total revenues or accounts receivable. At December 31, 2004, one non-affiliated customer comprised approximately 55% of the net Price-Risk Management Assets and Liabilities. At December 31, 2003, four non-affiliated customers comprised approximately 45% of the net Price-Risk Management Assets and Liabilities.
11. Related Party Transactions
American Electric Power Service Corporation (“AEPSC”), a wholly owned subsidiary of AEP and affiliate of HPL, provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable basis of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. For the years ended December 31, 2004, 2003 and 2002, HPL recognized costs of $5.5 million, $5.0 million and $5.4 million for these services.
HPL purchases and sells gas and enters into financial hedge transactions with AEPES and other affiliates. These transactions are conducted at market prices and settlements are handled according to standard industry practices. For the years ended December 31, 2004, 2003 and 2002, HPL had sales of $862.3 million, $899.2 million and $574.0 million and purchases of $760.3 million, $464.5 million and $388.2 million to and from AEPES. Included in these sales are settlement receipt (payments) of financial hedge transactions in 2004, 2003 and 2002 of $17.0 million, $(19.8) million and $(17.5) million.
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HPL CONSOLIDATION LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
HPL entered into a long-term Asset Management Agreement, which was terminated December 15, 2004, with AEPES for the exclusive rights to manage injections of natural gas into, and withdrawals of natural gas from, the Bammel storage facility, and to make use of natural gas injection, withdrawal and storage capacity not otherwise contractually committed by HPL that may be available from the Bammel storage facility from time to time. In exchange for these rights, AEPES agreed to pay HPL a fixed, annual Asset Management fee of $25 million. In addition, AEPES agreed to pay HPL a market based rate for storage services on the available space that was not contractually committed to third parties. For the period ended December 31, 2004, 2003 and 2002, HPL had revenues of $28.5 million, $29.8 million and $30.1 million related to the Asset Management Agreement.
AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries including HPL. Interest income earned from amounts advanced to the AEP money pool by HPL, for the twelve months ended December 31, 2004, 2003 and 2002, was $2.3 million, $2.5 million and $4.9 million. Interest expense incurred from amounts borrowed from the AEP money pool by HPL, for the twelve months ended December 31, 2004 was $.2 million. Interest income and expenses are recorded in Interest Income—Affiliated and Interest Expense—Affiliated on the Statements of Operations. Amounts loaned to or borrowed from the money pool at year-end are classified as Advances to/from Affiliates on the Consolidated Balance Sheets.
HPL purchases physical gas in the spot market, which in turn, is sold to AEP operating companies at cost for their fuel requirements. The related sales are as follows:
| Year Ended December 31, | |||||||||
| 2004 |
2003 |
2002 | |||||||
| (In thousands) | |||||||||
| AEP Texas Central Company |
$ | 129,682 | $ | 195,527 | $ | 157,346 | |||
| AEP Texas North Company |
45,767 | 44,197 | 64,385 | ||||||
There are certain immaterial liabilities recorded for guarantees entered subsequent to December 31, 2002 in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Prior to December 31, 2004, AEPESGH had outstanding debt, which was collateralized with the assets of HPL. This debt was paid in full on December 15, 2004.
Indemnifications And Other Guarantees
Contracts
HPL enters into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events.
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HPL CONSOLIDATION LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Master Operating Lease
We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2004, the maximum potential loss for these lease agreements was approximately $285 thousand assuming the fair market value of the equipment is zero at the end of the lease term.
On January 26, 2005, AEP sold a 98% controlling interest in us, approximately 30 Bcf of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. AEP is retaining a 2% ownership interest in us and will provide certain transitional administrative services to the buyer. AEP has provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA and certain other litigation. (See Note 3).
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Second Amended and Restated Agreement of Limited Partnership of
Energy Transfer Equity, L.P.
A-1
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Index to Financial Statements
Glossary of Terms
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this prospectus:
| /d |
per day |
| Bbls |
barrels | |
| Btu |
British energy an measurement thermal units, | |
| Mcf |
thousand feet cubic | |
| MMBtu |
million units British thermal | |
| MMcf |
million cubic feet | |
| Bcf |
Billion cubic feet | |
| NGLs |
natural as propane, and gasoline gas such natural butane liquids, | |
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Index to Financial Statements
Energy Transfer Equity, L.P.
15,000,000 Common Units
Representing Limited Partner Interests
PROSPECTUS
, 2005
Joint Book-Running Managers
UBS Investment Bank
Wachovia Securities
Credit Suisse First Boston
A.G. Edwards
RBC Capital Markets
Oppenheimer & Co.
Raymond James
Stephens Inc.
Table of Contents
Index to Financial Statements
PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
Item 13. Other Expenses Of Issuance And Distribution
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates.
| Commission registration fee |
$ | 40,607 | |
| NASD filing fee |
35,000 | ||
| NYSE listing fee |
* | ||
| Printing and engraving expenses |
700,000 | ||
| Fees and expenses of legal counsel |
650,000 | ||
| Accounting fees and expenses |
600,000 | ||
| Transfer agent and registrar fees |
20,000 | ||
| Tax and Structuring Fees |
600,000 | ||
| Miscellaneous |
* | ||
| Total |
$ | 3,000,000 | |
| * | To be provided by amendment. |
Item 14. Indemnification Of Directors And Officers.
The section of the prospectus entitled “Description of our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers and members of the board of directors of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section 7 of the Underwriting Agreement filed as an exhibit to this registration statement in which we will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in our partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.
To the extent that the indemnification provisions of our partnership agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.
Item 15. Recent Sales Of Unregistered Securities.
The following is a summary of our transactions during the past three years involving issuances of our securities that were not registered under the Securities Act:
1. The transactions below occurred on October 1, 2002:
| • | We sold a 1% general partner interest to LE GP, LLC in exchange for $1,578,949. |
| • | We sold 99% limited partner interests to various investors in exchange for the contribution of $110,771,051 and various entities owning midstream assets. These entities were subsequently contributed by us to La Grange Acquisition, LP, the predecessor to Energy Transfer Partners, L.P. |
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Index to Financial Statements
| • | We granted 12,145,749 incentive units to various employees and management. |
| • | We granted the following incentive units to ETC Holdings: 24,291,498 Tier I Units; 12,145,749 Tier II Units; 12,145,749 Tier III Units; 12,145,749 Tier IV Units. |
2. On November 1, 2002 we sold a .32% limited partner interest to Lon C. Kile in exchange for $500,000.
3. On January 19, 2004 we issued a .19% limited partner interest to E T Company, Ltd in exchange for its contribution of an office building and related contents.
Also on January 19, 2004 we issued an additional .16% limited partner interest to ETC Holdings, L.P. in exchange for its contribution of various entities that hold general partner interests in subsidiaries held by Energy Transfer Partners, L.P.
4. On June 15, 2005 we sold a 5% limited partner interest to FHM Investments, L.L.C. in exchange for its contribution of 1,638,692 Energy Transfer Partners, L.P. common units and its ownership of a 5% limited partner interest in Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.L.C.
The issuances of the securities described above were made in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act for transactions by an issuer not involving a public offering and, in the case of securities issued pursuant to the exercise of options previously granted, by Section 3(a)(10) of the Securities Act for securities issued in exchange for outstanding securities.
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Index to Financial Statements
Item 16. Exhibits and Financial Statement Schedules.
(a) The following documents are filed as exhibits to this registration statement with respect to exhibits that are incorporated by reference to Exchange Act filings, the Commission file number for Energy Transfer Products is 1-11727.:
| Exhibit Number |
Description | |
| 1.1** | Form of Underwriting Agreement | |
| 3.1* | Certificate of Conversion of Energy Transfer Company, L.P. | |
| 3.2* | Certificate of Limited Partnership of Energy Transfer Equity, L.P. | |
| 3.3** | Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. | |
| 3.4* | Certificate of Conversion of LE GP, LLC | |
| 3.5* | Certificate of Formation of LE GP, LLC | |
| 3.6** | Second Amended and Restated Limited Liability Company Agreement of LE GP, LLC | |
| 3.7 | Agreement of Limited Partnership of Heritage Propane Partners, L.P. (1) | |
| 3.7.1 | Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (8) | |
| 3.7.2 | Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (14) | |
| 3.7.3 | Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (17) | |
| 3.7.4 | Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (17) | |
| 3.7.5 | Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (22) | |
| 3.7.6 | Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (22) | |
| 3.7.7 | Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (35) | |
| 3.8 | Agreement of Limited Partnership of Heritage Operating, L.P. (1) | |
| 3.8.1 | Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P. (10) | |
| 3.8.2 | Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P. (17) | |
| 3.8.3 | Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P. (22) | |
| 3.9 | Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (22) | |
| 3.10 | Amended Certificate of Limited Partnership of Heritage Operating, L.P. (16) | |
| 3.11** | Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. | |
| 3.12** | Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. | |
| 3.13** | Certificate of Formation of Energy Transfer Partners, L.L.C. | |
| 3.14** | Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. | |
| 4.1 | Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association as trustee. (28) | |
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Index to Financial Statements
| Exhibit Number |
Description | |
| 4.2 | First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee. (29) | |
| 4.3 | Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005. (37) | |
| 4.4 | Notation of Guaranty. (38) | |
| 4.5 | Registration Rights Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto. (30) | |
| 4.6 | Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association as trustee. (39) | |
| 5.1** | Opinion of Vinson & Elkins LLP as to the legality of the securities being registered | |
| 8.1** | Opinion of Vinson & Elkins L.L.P. relating to tax matters | |
| 10.1† | Credit and Guaranty Agreement dated as of June 16, 2005 among Energy Transfer Company, L.P., the guarantors named therein, various lenders, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, Citicorp North America, Inc., as syndication agent, Lehman Commercial Paper Inc., as documentation agent, and Goldman Sachs Credit Partners L.P., Citigroup Markets Inc. and Lehman Brothers Inc., as lead arrangers and lead bookrunners. (43) | |
| 10.2 | Form of Note Purchase Agreement (June 25, 1996). (1) | |
| 10.2.1 | Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996. (2) | |
| 10.2.2 | Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997. (3) | |
| 10.2.3 | Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998. (5) | |
| 10.2.4 | Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement. (6) | |
| 10.2.5 | Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement. (9) | |
| 10.2.6 | Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement. (8) | |
| 10.2.7 | Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (11) | |
| 10.2.8 | Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (22) | |
| 10.3 | Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P. (1) | |
| 10.6† | Restricted Unit Plan. (1) | |
| 10.6.1† | Amendment of Restricted Unit Plan dated as of October 17, 1996. (3) | |
| 10.6.2† | Amended and Restated Restricted Unit Plan dated as of August 10, 2000. (10) | |
| 10.6.3† | Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002. (16) | |
| 10.6.4† | 2004 Unit Plan. (26) | |
| 10.6.5† | Form of Grant Agreement. (27) | |
| 10.16 | Note Purchase Agreement dated as of November 19, 1997. (4) | |
| 10.16.1 | Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement. (5) | |
| 10.16.2 | Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement. (6) | |
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Index to Financial Statements
| Exhibit Number |
Description | |
| 10.16.3 | Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement. (7) | |
| 10.16.4 | Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement. (8) | |
| 10.16.5 | Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (11) | |
| 10.16.6 | Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (23) | |
| 10.17 | Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P. (8) | |
| 10.17.1 | Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement. (8) | |
| 10.18 | Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors. (8) | |
| 10.18.1 | Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement. (8) | |
| 10.18.2 | Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement. (14) | |
| 10.18.3 | Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement. (15) | |
| 10.19 | Note Purchase Agreement dated as of August 10, 2000. (8) | |
| 10.19.1 | Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (11) | |
| 10.19.2 | First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement. (12) | |
| 10.19.3 | Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement. (23) | |
| 10.20 | Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of ProFlame, Inc. and Heritage Holdings, Inc. (13) | |
| 10.21 | Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of Coast Liquid Gas, Inc. and Heritage Holdings, Inc. (13) | |
| 10.22 | Agreement and Plan of Merger dated as of July 5, 2001 among California Western Gas Company, the Majority Stockholders of California Western Gas Company signatories thereto, Heritage Holdings, Inc. and California Western Merger Corp. (13) | |
| 10.23 | Agreement and Plan of Merger dated as of July 5, 2001 among Growth Properties, the Majority Shareholders signatories thereto, Heritage Holdings, Inc. and Growth Properties Merger Corp. (13) | |
| 10.24 | Asset Purchase Agreement dated as of July 5, 2001 among L.P.G. Associates, the Shareholders of L.P.G. Associates and Heritage Operating, L.P. (13) | |
| 10.25 | Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P. (13) | |
| 10.25.1 | Amendment to Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P. (13) | |
| 10.26 | Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P. dated as of February 4, 2002. (16) | |
II-5
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Index to Financial Statements
| Exhibit Number |
Description | |
| 10.27 | Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P., dated as of February 4, 2002. (16) | |
| 10.28 | Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002 amount V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P. (19) | |
| 10.30 | Acquisition Agreement dated November 6, 2003 among the owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and La Grange Energy, L.P. (20) | |
| 10.31 | Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P. (20) | |
| 10.31.1 | Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P. (21) | |
| 10.32 | Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P. (20) | |
| 10.35 | Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004. (24) | |
| 10.35.1 | First Amendment to Purchase and Sale Agreement and Closing Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated June 1, 2004. (24) | |
| 10.36 | Third Amended and Restated Credit Agreement among Heritage Operating L.P. and the Banks dated March 31, 2004. (25) | |
| 10.40 | Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland PLC, as co-documentation agents, and other lenders party thereto. (31) | |
| 10.40.1 | First Amendment to Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland PLC, as co-documentation agents, and other lenders party thereto. (40) | |
| 10.41 | Guaranty, dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders. (32) | |
| 10.41.1 | Guaranty Supplement dated February 24, 2005. (40) | |
| 10.42 | Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and La Grange Acquisition, L.P., as Buyer. (33) | |
| 10.43 | Cushion Gas Litigation Agreement dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies. (34) | |
| 10.44 | Loan Agreement dated as of January 26, 2005 between La Grange Acquisition, L.P., as Borrower, and La Grange Energy, L.P., as Lender. (36) | |
| 10.45 | Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P. (41) | |
| 10.46 | Unitholder Rights Agreement dated January 20, 2004 among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and La Grange Energy, L.P. (42) | |
| 10.47**† | Employment Agreement with John W. McReynolds | |
| 10.48**† | Energy Transfer Equity Long-Term Incentive Plan | |
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Index to Financial Statements
| Exhibit Number |
Description | |
| 10.49**† | Form of Director and Officer Indemnification Agreement | |
| 21.1** | List of Subsidiaries. | |
| 23.1* | Consent of Grant Thornton LLP | |
| 23.2* | Consent of Deloitte & Touche LLP | |
| 23.3* | Consent of Deloitte & Touche LLP | |
| 23.4* | Consent of Ernst & Young LLP | |
| 23.5** | Consent of Vinson & Elkins LLP (contained in Exhibit 5.1) | |
| 23.6** | Consent of Vinson & Elkins LLP (contained in Exhibit 8.1) | |
| 24.1* | Powers of Attorney (set forth on the signature pages to this Registration Statement) | |
| * | Filed herewith. |
| ** | To be filed by Amendment. |
| † | Denotes a management contract or compensatory plan or arrangement. |
| (1) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Registration Statement on Form S-1, File No. 333-04018, filed with the Commission on June 21, 1996. |
| (2) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended November 30, 1996. |
| (3) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 1997. |
| (4) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 1998. |
| (5) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-K for the year ended August 31, 1998. |
| (6) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-K for the year ended August 31, 1999. |
| (7) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 2000. |
| (8) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 8-K dated August 23, 2000. |
| (9) | Filed as Exhibit 10.16.3. |
| (10) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-K for the year ended August 31, 2000. |
| (11) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2001. |
| (12) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 2001. |
| (13) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 8-K dated August 15, 2001. |
| (14) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-K for the year ended August 31, 2001. |
| (15) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended November 30, 2001. |
| (16) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2002. |
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| (17) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 2002. |
| (18) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 8-K dated February 4, 2002. |
| (19) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 8-K dated January 6, 2003. |
| (20) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 2003. |
| (21) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended November 30, 2003. |
| (22) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 29, 2004. |
| (23) | Incorporated by reference to Exhibit 10.28 to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 29, 2004. |
| (24) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 8-K filed June 14, 2004. |
| (25) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended May 31, 2004. |
| (26) | Incorporated by reference to Annex A of Energy Transfer Partners, L.P.’s Schedule 14A Proxy Statement filed May 18, 2004. |
| (27) | Incorporated by reference to Exhibit 10.1 to Energy Transfer Partners, L.P.’s Form 8-K filed November 1, 2004. |
| (28) | Incorporated by reference to Exhibit 4.1 to Energy Transfer Partners, L.P.’s Form 8-K filed January 19, 2005. |
| (29) | Incorporated by reference to Exhibit 4.2 to Energy Transfer Partners, L.P.’s Form 8-K filed January 19, 2005. |
| (30) | Incorporated by reference to Exhibit 4.3 to Energy Transfer Partners, L.P.’s Form 8-K filed January 19, 2005. |
| (31) | Incorporated by reference to Exhibit 10.1 to Energy Transfer Partners, L.P.’s Form 8-K filed January 19, 2005. |
| (32) | Incorporated by reference to Exhibit 10.2 to Energy Transfer Partners, L.P.’s Form 8-K filed January 19, 2005. |
| (33) | Incorporated by reference to Exhibit 10.1 to Energy Transfer Partners, L.P.’s Form 8-K filed February 1, 2005. |
| (34) | Incorporated by reference to Exhibit 10.2 to Energy Transfer Partners, L.P.’s Form 8-K filed February 1, 2005. |
| (35) | Incorporated by reference to Exhibit 3.1.7 to Energy Transfer Partners, L.P.’s Form 8-K filed March 16, 2005. |
| (36) | Incorporated by reference to Exhibit 10.3 to Energy Transfer Partners, L.P.’s Form 8-K filed March 17, 2005. |
| (37) | Incorporated by reference to Exhibit 10.45 to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2005. |
II-8
Table of Contents
Index to Financial Statements
| (38) | Incorporated by reference to Exhibit 10.46 to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2005. |
| (39) | Incorporated by reference to Exhibit 10.39.1 to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2005. |
| (40) | Incorporated by reference to the same numbered Exhibit to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 28, 2005. |
| (41) | Incorporated by reference to Exhibit 4.1 to Energy Transfer Partners, L.P.’s Form 8-K dated February 4, 2002. |
| (42) | Incorporated by reference to Exhibit 4.2 to Energy Transfer Partners, L.P.’s Form 10-Q for the quarter ended February 29, 2004. |
| (43) | Incorporated by reference to Exhibit 99.F to Energy Transfer Partners, L.P.’s Schedule 13D/A filed June 24, 2005. |
Item 17. Undertakings.
The undersigned Registrant hereby undertakes to provide at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the Underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
(2) For the purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with LE GP, LLC, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to LE GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.
II-9
Table of Contents
Index to Financial Statements
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Dallas, State of Texas, on September 2, 2005.
| ENERGY TRANSFER EQUITY, L.P. | ||
| By: |
LE GP, LLC its general partner | |
| By: |
/S/ JOHN W. MCREYNOLDS | |
| Name: |
John W. McReynolds | |
| Title: |
President and Chief Financial Officer | |
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints John W. McReynolds his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any additional registration statement pursuant to Rule 462(b), and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully and to all intents and purposes as he might or could not do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities indicated on the 2nd day of September, 2005.
| Signature |
Title | |
| /S/ JOHN W. MCREYNOLDS John W. McReynolds |
Director, President and Chief Financial Officer of LE GP, LLC, general partner of Energy Transfer Equity, L.P. (Principal Executive, Financial, and Accounting Officer) | |
| /S/ DAVID R. ALBIN David R. Albin |
Director of LE GP, LLC, general partner of Energy Transfer Equity, L.P. | |
| /S/ KENNETH A. HERSH Kenneth A. Hersh |
Director of LE GP, LLC, general partner of Energy Transfer Equity, L.P. | |
| /S/ DANIEL A. RIOUX Daniel A. Rioux |
Director of LE GP, LLC, general partner of Energy Transfer Equity, L.P. | |
| /S/ K. RICK TURNER K. Rick Turner |
Director of LE GP, LLC, general partner of Energy Transfer Equity, L.P. | |
II-10
Exhibit 3.1
CERTIFICATE OF CONVERSION
OF
ENERGY TRANSFER COMPANY, L.P.
(a Texas limited partnership)
TO
ENERGY TRANSFER EQUITY, L.P.
(a Delaware limited partnership)
UNDER SECTION 17-217 OF
THE DELAWARE REVISED UNIFORM
LIMITED PARTNERSHIP ACT
1. The jurisdiction where the limited partnership was first formed is Texas.
2. The date on which the limited partnership was first formed is September 5, 2002 and name under which the limited partnership’s certificate of limited partnership was originally filed is La Grange Energy, L.P.
3. The name of the limited partnership immediately prior to the filing of this certificate is Energy Transfer Company, L.P.
4. The name of the limited partnership as set forth in its Certificate of Limited Partnership filed in accordance with Section 17-217(b) is Energy Transfer Equity, L.P.
5. The conversion is to be effective upon the filing of this Certificate of Conversion and the Certificate of Limited Partnership.
IN WITNESS WHEREOF, the undersigned has executed this Certificate of Conversion as of August , 2005.
| ENERGY TRANSFER EQUITY, L.P. | ||
| By: | LE GP, LLC, its general partner | |
| By: |
/s/ John W. McReynolds
| |
| Name: |
John W. McReynolds | |
| Title: |
President | |
Exhibit 3.2
CERTIFICATE OF LIMITED PARTNERSHIP
OF
ENERGY TRANSFER EQUITY, L.P.
This Certificate of Limited Partnership, dated August , 2005, has been duly executed and is filed pursuant to Section 17-201 of the Delaware Revised Uniform Limited Partnership Act (the “Act”) to form a limited partnership under the Act.
1. Name. The name of the limited partnership is “Energy Transfer Equity, L.P.”
2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 17-104 of the Act is:
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801.
The name and the address of the registered agent for service of process required to be maintained by Section 17-104 of the Act are:
The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801.
3. General Partner. The name and the business, residence or mailing address of the general partner are:
LE GP, LLC
2828 Woodside Drive
Dallas, Texas 75204
EXECUTED as of the date written first above.
| LE GP, LLC | ||
| its General Partner | ||
| By: | /s/ John W. McReynolds
| |
| Name: |
John W. McReynolds | |
| Title: |
President | |
Exhibit 3.4
CERTIFICATE OF CONVERSION
OF
LE GP, LLC
(a Texas limited liability company)
TO
LE GP, LLC
(a Delaware limited liability company)
UNDER SECTION 18-214 OF
THE DELAWARE LIMITED LIABILITY COMPANY ACT
1. The jurisdiction where the limited partnership was first formed is Texas.
2. The date on which the limited liability company was first formed is September 4, 2002 and the name under which the limited liability company’s articles of organization was originally filed is LE GP, LLC.
3. The name of the limited liability company immediately prior to the filing of this certificate is LE GP, LLC and its current state of formation is Texas.
4. The name of the limited liability company as set forth in its Certificate of Formation filed in accordance with Section 18-214 is LE GP, LLC.
5. The conversion is to be effective upon the filing of this Certificate of Conversion and the Certificate of Formation.
IN WITNESS WHEREOF, the undersigned has executed this Certificate of Conversion as of August , 2005.
| LE GP, LLC | ||
| By: | /s/ John W. McReynolds | |
| Name: |
John W. McReynolds | |
| Title: |
President | |
Exhibit 3.5
CERTIFICATE OF FORMATION
OF
LE GP, LLC
This Certificate of Formation, dated August , 2005, has been duly executed and is filed pursuant to Sections 18-201 and 18-204 of the Delaware Limited Liability Company Act (the “Act”) to form a limited liability company (the “Company”) under the Act.
1. Name. The name of the Company is:
LE GP, LLC
2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 18-104 of the Act is:
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801.
The name and the address of the registered agent for service of process required to be maintained by Section 18-104 of the Act are:
The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801.
EXECUTED as of the date written first above.
| By: | /s/ John W. McReynolds | |
| Name: |
John W. McReynolds | |
| Title: |
President | |
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued i) our reports dated September 1, 2005 accompanying the consolidated financial statements of Energy Transfer Equity, L.P. as of August 31, 2004 and 2003 and for the year ended August 31, 2004 and the eleven months ended August 31, 2003; and the consolidated balance sheet of LE GP, LLC as of August 31, 2004; ii) our report dated November 11, 2004 accompanying the consolidated financial statements of Heritage Propane Partners, L.P. as of August 31, 2003 and for the period ended January 19, 2004 and for each of the two years in the period ended August 31, 2003; and iii) our report dated October 25, 2002 accompanying the financial statements of Bi-State Propane as of and for the year ended August 31, 2002, contained in the Registration Statement on Form S-1 of Energy Transfer Equity, L.P. We consent to the use of the aforementioned reports in the Registration Statement and to the use of our name as it appears under the caption “Experts”.
/s/ Grant Thornton LLP
Tulsa, Oklahoma
September 1, 2005
Exhibit 23.2
CONSENT OF INDEPENDENT AUDITORS
We consent to the use in this Registration Statement of Energy Transfer Equity, L.P. on Form S-1 of our report dated June 11, 2004, related to the financial statements of TXU Fuel Company as of and for the years ended December 31, 2003 and 2002 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 143), appearing in the prospectus, which is part of this Registration Statement and to the reference to us under the heading “Experts” in such Prospectus.
/s/ Deloitte & Touche LLP
Dallas, Texas
September 1, 2005
Exhibit 23.3
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the use in this Registration Statement of Energy Transfer Equity, L.P. on Form S-1 of our report dated March 15, 2005, related to the financial statements of HPL Consolidation LP as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004, appearing in the prospectus, which is part of this Registration Statement, and to the reference to us under the heading “Experts” in such prospectus.
/s/ Deloitte & Touche LLP
Houston, Texas
September 1, 2005
Exhibit 23.4
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the reference to our firm under the caption “Experts” and to the use of our report dated July 17, 2003 with respect to the consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and the nine month period then ended and the year ended December 31, 2001, and our report dated July 15, 2003 with respect to the consolidated financial statements of Oasis Pipe Line Company and Subsidiaries as of December 27, 2002 and the period then ended, in the Registration Statement on Form S-1 and related Prospectus of Energy Transfer Equity, L.P. dated September 2, 2005.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
September 1, 2005