Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-K

 


 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended August 31, 2006

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from              to             

Commission file number 001-32740

 


ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

 


 

Delaware   30-0108820

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

2828 Woodside Street, Dallas, Texas 75204

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

 


Securities registered pursuant to Section 12(b) of the Act:

 

Title of class

 

Name of each exchange on

which registered

Common Units   New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None

 


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨    Accelerated filer  ¨    Non accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value as of February 28, 2006, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date, was approximately $1,389,800,000. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

At November 15, 2006, the registrant had units outstanding as follows:

 

Energy Transfer Equity, L.P.        124,360,520 Common Units
   2,521,570 Class B Units
   83,148,900 Class C Units

Documents Incorporated by Reference: None

 



Table of Contents

ENERGY TRANSFER EQUITY, L.P.

2006 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

          PAGE
   PART I   
ITEM 1.   

BUSINESS

   1
ITEM 1A.   

RISK FACTORS

   20
ITEM 1B.   

UNRESOLVED STAFF COMMENTS

   41
ITEM 2.   

PROPERTIES

   41
ITEM 3.   

LEGAL PROCEEDINGS

   43
ITEM 4.   

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   43
   PART II   
ITEM 5.   

MARKET FOR THE REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

   44
ITEM 6.   

SELECTED FINANCIAL DATA

   45
ITEM 7.   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   47
ITEM 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   78
ITEM 8.   

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

   82
ITEM 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

   142
ITEM 9A.   

CONTROLS AND PROCEDURES

   143
ITEM 9B.   

OTHER INFORMATION

   143
   PART III   
ITEM 10.   

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   143
ITEM 11.   

EXECUTIVE COMPENSATION

   147
ITEM 12.   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

   150
ITEM 13.   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   152
ITEM 14.   

PRINCIPAL ACCOUNTANT FEES AND SERVICES

   154
   PART IV   
ITEM 15.   

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

   155


Table of Contents

PART I

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by us in periodic press releases and some oral statements of our officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect”, “continue,” “estimate,” “goal,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we and our General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, neither we or 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. When considering forward-looking statements, please read the section titled “Risk Factors” included under Item 1A of this annual report.

ITEM 1. BUSINESS

Overview

We are a publicly traded Limited Partnership, formerly known as La Grange Energy, L.P. Our Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE”. We were formed in September 2002 and completed our IPO of 24,150,000 Common Units in February 2006.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners G.P., L.P (“ETP GP”), the General Partner of ETP, and ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). References to “the Parent Company” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.

The Parent Company’s only cash generating assets are its direct and indirect investments in limited partner and general partner interests in ETP. After the acquisition of ETP Class G Units and the remaining 50% of the ETP incentive distribution rights on November 1, 2006, as discussed below, the Parent Company’s direct and indirect ownership of ETP consisted of approximately 36.4 million Common Units, 26.1 million Class G Units, the 2% General Partner interests and 100% of the Incentive Distribution Rights. During the fiscal year ended August 31, 2006 the Parent Company received distributions of $80.2 million, $4.6 million and $64.4 million related to its limited partner interests, general partner interests and Incentive Distribution Rights of ETP, respectively. Distributions on the general partner interests were net of $2.3 million held back for ETP GP’s contribution to maintain its 2% general partner interest in ETP and reimbursement of expenses.

The Parent Company’s business operations currently are conducted only through ETP’s wholly-owned subsidiaries, ETC OLP, a Texas limited partnership engaged in midstream and transportation and natural gas storage operations, Heritage Operating, L.P. (referenced herein as “HOLP”), a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan Energy Partners, L.P., a Delaware Limited Partnership engaged in retail propane operations (collectively referred to as the “Operating Partnerships”).

ETP’s Operations

Our midstream and transportation and storage businesses own and operate approximately 12,000 miles of natural gas gathering and transportation pipelines, with an additional 600 miles under construction, three natural gas processing plants, two of which are connected to our gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities located in Texas. Through ETC OLP, we conduct our natural gas midstream and transportation and storage businesses through two segments, the midstream segment and the transportation and storage segment. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of

 

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natural gas 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. Our 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 our Oasis Pipeline, our East Texas Pipeline, our Fort Worth Basin Pipeline, our natural gas pipeline and storage assets that are referred to as the ET Fuel System, and our Houston Pipeline System, which are described below.

Through HOLP and Titan, we are one of the three largest retail marketers of propane in the United States, serving more than one million customers from 442 customer service locations in 41 states. Our propane operations extend from coast to coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States.

For the year ended August 31, 2006, on a consolidated basis, we had revenues of approximately $7.9 billion, operating income of approximately $575.5 million and net income of approximately $107.1 million.

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

 

/d    per day
Bbls    barrels
Btu    British thermal unit, an energy measurement
Mcf    thousand cubic feet
MMBtu    million British thermal unit
MMcf    million cubic feet
Bcf    billion cubic feet
NGL    natural gas liquid, such as propane, butane and natural gasoline
Tcf    trillion cubic feet
LIBOR    London Interbank Offered Rate
NYMEX    New York Mercantile Exchange
Reservoir    A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P. (“Heritage”) and the Parent Company completed a series of transactions whereby the Parent Company contributed its subsidiary, 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 the Parent Company 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 the Parent Company and an affiliate of the Parent Company contributed an office building to ETC OLP. The Parent Company also received 7,485,030 ETP Special Units as consideration for the project it had in progress to construct the Bossier Pipeline now referred to as the East Texas Pipeline. The ETP Special Units converted to ETP Common Units upon the East Texas Pipeline becoming commercially operational and such conversion being approved by ETP’s Unitholders. The East Texas Pipeline became commercially operational on June 21, 2004, and the ETP Unitholders approved the conversion of the ETP Special Units at a special meeting held on June 23, 2004.

Simultaneously with the transactions described in the preceding paragraph, the Parent Company obtained control of Heritage by acquiring all of the interests in ETP GP, formerly U.S. Propane, L.P., the General Partner of Heritage, and ETP GP’s General Partner, ETP LLC formerly U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30.0 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”) for $100.0 million.

 

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Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325.0 million from financial institutions and Heritage raised $355.9 million of gross proceeds net of underwriter’s discount, through the sale of 18,400,000 Common Units at an offering price of $19.34 per ETP unit. The net proceeds were used to finance the Energy Transfer Transactions and for ETP general partnership purposes.

The above historical ETP units and per ETP unit offering price have been restated to reflect a two-for-one split effected March 2005.

Recent Acquisitions and Expansions

On November 10, 2005, we acquired the remaining 2% limited partner interest in HPL Consolidation, L.P. (“HPL”) for $16.6 million in cash. (We purchased 98% of HPL in January 2005.) The purchase price was allocated to property, plant and equipment and the minority interest liability associated with the 2% limited partner interest was eliminated. As a result, HPL became a wholly-owned subsidiary of ETC OLP.

Prior to November 2005, we owned a 50% interest in South Texas Gas Gathering, a joint venture that owned an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. We purchased the remaining 50% equity interest in South Texas Gas Gathering in November 2005 for $0.7 million.

On June 1, 2006, we acquired all the propane operations of Titan Energy Partners, LP and Titan Energy, GP LLC (collectively “Titan”) for cash of approximately $548.0 million, after working capital adjustments and net of cash acquired, and liabilities assumed of approximately $46.0 million. This acquisition was initially financed by borrowings under the ETP Revolving Credit Facility. Titan’s propane assets primarily consist of retail propane operations in 33 states conducted from 146 district locations located in high growth areas of the U.S. The addition of the Titan assets expanded our retail propane operations into six additional states and several new operating territories in which we did not previously have operations. This expansion will further reduce the impact on the propane operations from weather patterns in any one area of the U.S., while continuing our focus on conducting the retail propane operations in attractive high-growth areas.

During the fiscal year ended August 31, 2006, HOLP and Titan collectively acquired substantially all of the assets of eight propane businesses. The aggregate purchase price for these acquisitions totaled $28.9 million.

In June 2006 we and Atmos Energy Corporation (“Atmos”) completed the North Side Loop (“NSL”) pipeline, a 45-mile, 30-inch pipeline system. The pipeline was constructed for the purpose of providing producers in the Ft. Worth Basin with pipeline capacity to reach markets on both Atmos’ and our pipeline systems. The pipeline will also provide a significant amount of supply for the growing demand for natural gas north of the Dallas/Fort Worth metroplex. The pipeline has a throughput capacity of 450 MMcf/d with the ability to expand with increased compression. We own 50% of the pipeline which cost $75.4 million to construct.

Other Developments

On August 31, 2006 we announced the completion of the first phase of our previously announced 42-inch pipeline construction project. This segment, comprised of 97 miles of 42-inch natural gas pipeline, connects our 30-inch pipeline in Freestone County, the Bethel Storage Facility and its 30-inch Texoma pipeline in Rusk County. This portion of the 42-inch project has been placed in service and is currently flowing natural gas. The completion of this first phase provides us with additional take-away capacity to transport gas out of the Barnett Shale and Bossier Sands producing areas.

The full benefit to the Partnership of the 42-inch construction project will be recognized upon completion of the additional phases, all of which are currently underway and are on schedule to be completed by March 2007. Because of increased transportation commitments to ETP, ETP’s Board of Directors approved a plan to upsize the recently announced 157 mile 36-inch expansion of this project to 42-inch for the section that runs from Limestone County, Texas to the interconnect with our Texoma pipeline, northeast of Beaumont. The increased upsizing will bring the estimated total cost of the project from $895.0 million to approximately $1.0 billion.

 

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On September 15, 2006, ETP announced the execution of agreements with GE Energy Financial Services (“GE”) and Southern Union Company to acquire the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. The agreements provide for a series of transactions in which we will acquire all of the member interests in CCE Holdings, LLC (“CCEH”) owned by GE and certain other investors. The member interests acquired will represent a 50% ownership in CCEH, which was formed in 2004 to purchase CrossCountry Energy. In the second transaction, CCEH will redeem our 50% ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”), following which Southern Union Company (“Southern Union”) will own all of the member interests of CCEH. On November 1, 2006, ETP acquired the member interests in CCEH from GE and certain other investors for $1 billion and expects to complete the remaining series of transactions in the second quarter of fiscal year 2007. Upon closing ETP expects the acquisition to be immediately accretive to our Common Unitholders. ETP financed the purchase price with the issuance of approximately 26.1 million Class G Units issued to the Parent Company simultaneous with the closing on November 1, 2006, as discussed below.

The Transwestern Pipeline connects supply areas in the San Juan Basin in southern Colorado and northern New Mexico, the Anadarko Basin in the Mid-continent and the Permian Basin in west Texas to markets in the Midwest, Texas, Arizona, New Mexico and California. The Transwestern Pipeline interconnects with our existing intrastate pipelines in west Texas. The combination of pipeline systems will result in new market opportunities for existing natural gas supply sources on both systems and increases supply availability and flexibility to existing markets served by both systems.

On October 3, 2006, ETP announced that we entered into a long-term agreement with CenterPoint Energy Resources Corp (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on our HPL System located along the Texas gulf coast region. Under the terms of this agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in our Bammel Storage facility. Under the new agreement with CenterPoint, we will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for the supplying of CenterPoint’s winter needs. This will reduce our working capital requirements that were necessary to finance the working gas while in storage and will provide us an opportunity to offer storage to third parties. This agreement goes into effect beginning April 1, 2007.

On September 20, 2006, ETP announced two internal growth projects:

 

  a natural gas processing facility in Johnson County, Texas. The processing facility is being built in two phases to process rich natural gas produced from the Barnett Shale and will connect with our existing pipeline infrastructure. Phase I consists of a cryogenic gas plant with capacity of 115 MMcf/d, which is expected to be in service by the end of November 2006. Phase II of the project includes another 170 MMcf/d cryogenic gas plant and a 100 MMcf/d hydrocarbon dew point refrigeration plant, and is expected to be completed by the end of June 2007. The facility is being built to accommodate additional expansion in the future. This facility will be one of the few North Texas natural gas processing plants with access to two NGL pipelines. The cost for this project is approximately $65.0 million; and

 

  a 36-inch pipeline expansion connecting the Barnett Shale to our ETP 30-inch Texoma pipeline. The 36-inch pipeline expansion is the result of our continued success in contracting transportation volumes. This 135-mile pipeline connects our existing Forth Worth Basin system to our 30-inch Texoma pipeline in Lamar County, Texas. The project expands producers’ options by providing additional market opportunities including access to the Carthage hub, interstate pipelines and industrial users along the Houston Ship Channel. It includes 27 miles of 30-inch pipe, 108 miles of 36-inch pipe and 64,000 horsepower of compression with an initial capacity of 700 MMcf/d with expansion capabilities up to 1.0 Bcf/d. This project will cost approximately $300.0 million to construct.

In September 2006 ETP also acquired two small gathering systems in east and north Texas for an aggregate purchase price of $30.0 million. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25.0 million to be determined eighteen months from the closing date. These systems provide us with additional capacity in the Barnett Shale and in the Travis Peak area of east Texas.

On November 1, 2006, ETP issued approximately 26.1 million of its Class G Units to the Parent Company for $1.2 billion, at a price of $46.00 per unit based upon a negotiated discount from the closing price of ETP’s Common Units on October 31, 2006. The ETP Class G Units were issued to the Parent Company with registration rights. ETP used the proceeds of $1.2 billion to fund a portion of the Transwestern Pipeline acquisition and to repay

 

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indebtedness ETP incurred in connection with the Titan acquisition as discussed above. The terms of the Class G Units are substantially similar to those of ETP’s Class F Units previously issued to the Parent Company, as discussed in Note 7 to our consolidated financial statements.

On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.

In a separate but related transaction, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”), the remaining 50% general partner Incentive Distributions Rights (“IDRs”) of ETP, which resulted in the Parent Company now owning 100% of the IDRs. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units for all ETI interests.

Parent Company – Energy Transfer Equity, L.P.

Currently, the Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in Limited and General Partner ownership interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Partnerships.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included herein discussions of Parent Company matters apart from those of our consolidated group.

ETP’s Operations

ETC OLP (Midstream and Transportation and Storage Operations)

The following map depicts our natural gas pipeline and storage systems:

LOGO

 

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Our midstream segment consists of the following:

 

  The Southeast Texas System, a 4,250-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, the Madison processing plant, and seven treating facilities. 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 and Madison processing plants are cryogenic natural gas processing plants that process the rich natural gas that flows through our system to produce residue gas and NGLs. The plants have a processing capacity of approximately 320 MMcf/d. Our seven treating facilities have an aggregate capacity of 730 MMcf/d. These treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.

 

  Interests in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, and the Chalkley Transmission System. On a combined basis, these assets have a capacity of approximately 560 MMcf/d.

 

  Marketing operations through our producer services business, in which we market the natural gas that flows through our assets, referred to as on-system gas, and attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell 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 our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or our transportation pipelines. For the off-system gas, we purchase gas or act as an agent for small independent producers that do not have marketing operations. We develop relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business provides us with strategic insight and market intelligence, which may impact our expansion and acquisition strategy.

Our 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 has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

The Oasis Pipeline is integrated with our Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System by:

 

    providing us with the ability to bypass the La Grange processing plant when processing margins are unfavorable;

 

    providing access for natural gas on the Southeast Texas System to other third party supply and market points and interconnecting pipelines; and

 

    allowing us to bypass our 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 2,100 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

 

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natural gas. The ET Fuel System operates our 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 our 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. Integrated into our ET Fuel System is our Fort Worth Basin Pipeline, which became operational on May 26, 2005. The Fort Worth Basin Pipeline is a 55-mile, 24-inch natural gas pipeline that connects our 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 our previously disclosed expansion program that was implemented to integrate our 36-inch Katy Pipeline and the Southeast Texas System assets with the ET Fuel System and the Houston Pipeline System.

 

  The East Texas Pipeline is a 148-mile natural gas pipeline that connects three treating facilities, one of which we own, with our Southeast Texas System. This pipeline was the first phase of a multi-phased project that increased service to producers in East and North Central Texas and provided access to the Katy Hub. The East Texas Pipeline expansion had an initial capacity of over 400 MMcf/d which increased to the current capacity of 675 MMcf/d with the addition of the Grimes County Compressor Station. Over 500 MMcf/d of pipeline capacity is 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 related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast of Texas, 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 and has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contributes to our 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 our operation of the Bammel storage facility. The Bammel storage facility has a total working gas capacity of approximately 65 Bcf and 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.

Heritage Operating, L.P. and Titan Operating, L.P.

Through HOLP and Titan, we are one of the three largest retail propane marketers in the United States, based on gallons sold. We serve more than one million customers from 442 customer service locations in 41 states. Our propane operations extend from coast to coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. We are also a wholesale propane supplier in the southwestern and southeastern United States and in Canada, the latter through participation in M-P Energy Partnership. M-P Energy Partnership is a Canadian partnership in which we own a 60% interest that is engaged in wholesale distribution and in supplying our northern U.S. locations. Our propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth.

Following is a summary of the retail sales volumes per fiscal year for the last three fiscal years:

 

    

For the Years Ended

August 31,

     2006    2005    2004    2004
               (Actual)    (Aggregate)

Retail Gallons Sold (in millions)

   429.1    406.3    226.2    397.9

We present retail gallons sold for fiscal year 2004 on the basis of (1) an aggregate total reflecting Heritage’s historical results from September 1, 2003 until the closing of the Energy Transfer Transactions on January 19, 2004, and (2) Heritage’s historical results reflecting the actual results for the fiscal year ended August 31, 2004, for comparability purposes only. The 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.

 

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For the year ended August 31, 2006, the retail gallons sold include 24.5 million gallons of retail sales volumes for Titan for the period from the date we acquired Titan (June 1, 2006) through August 31, 2006.

Business Strategy

The Parent Company Business Strategy

Our primary business objective is to increase our cash distributions to our Unitholders by actively assisting ETP in executing its business strategy by assisting in identifying, evaluating, and pursuing acquisitions and growth opportunities. In general, we expect that we will allow ETP the first opportunity to pursue any acquisition or internal growth project that may be presented to us which is within the scope of ETP’s operations or business strategy. 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 Business Strategy

ETP’s primary objective is to increase Unitholder distributions and the value of its Common Units. We believe ETP 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 our 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 ETP Common Unit. We believe that by pursuing independent operating and growth strategies for ETP’s midstream, transportation and storage and propane businesses, we will be best positioned to achieve our objectives.

We expect that acquisitions in our midstream and transportation and storage segments will be the primary focus of our acquisition strategy going forward, as evidenced by the recently announced plan to acquire the Transwestern Pipeline System, although we will also continue to pursue complementary propane acquisitions, as evidenced by our acquisition of Titan in June 2006. We also anticipate that our midstream and transportation and storage businesses will provide internal growth projects of greater scale compared to those available in our propane business, as demonstrated by our 42-inch pipeline project and other recently announced projects.

Midstream and Transportation and Storage Business Strategies

Enhance profitability of existing assets. We intend to increase the profitability of our 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. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream services. These projects include those discussed above and include the construction of the 42-inch pipeline project, the natural gas processing facility in Johnson County, Texas, and a 36-inch pipeline expansion connecting the Barnett Shale to our 30-inch Texoma pipeline. We expect that these expansions will lead to additional growth opportunities in this area.

Increase cash flow from fee-based businesses in our midstream segment. Excluding results from our marketing activities, the portion of our gross margin in the midstream segment attributable to fee-based business has continued to increase. We charge fees for providing midstream services, including gathering, compressing, treating, processing and transmitting natural gas for producers. These fee-based services are dependent on throughput volume and are typically less affected by short-term changes in commodity prices. We intend to seek to increase the percentage of our midstream business conducted with third parties under fee-based arrangements in order to reduce our exposure to changes in the prices of natural gas and NGLs.

Growth through acquisitions. As demonstrated by our acquisitions of the gathering systems in north and east Texas and the recent announcement of the Transwestern Pipeline acquisition, we intend to make strategic acquisitions of midstream, transportation and storage assets in our current areas of operation that offer the opportunity for

 

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operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets. We 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. We believe that we will be well positioned to benefit from any additional acquisition opportunities that may 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, we have aggressively focused on high return internal growth opportunities at our existing customer service locations. We believe that by concentrating our operations in areas experiencing higher-than-average population growth, we are well positioned to achieve internal growth by adding new customers.

Growth through complementary acquisitions. We believe that our position as one of the three largest propane marketers in the United States provides us a solid foundation to continue our acquisition growth strategy through consolidation. We believe that the fragmented nature of the propane industry will continue to provide opportunities for growth through the acquisition of propane businesses that complement our existing asset base. In addition to focusing on propane acquisition candidates in our existing areas of operations, we will also consider core acquisitions in other higher-than-average population growth areas in which we have no presence in order to further reduce the impact adverse weather patterns and economic downturns in any one region could have on our overall operations.

Maintain low-cost, decentralized operations. We focus on controlling costs, and we attribute our low overhead costs primarily to our 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, we have been able to operate without a large corporate staff. In addition, our customer service location level incentive compensation program encourages employees at all levels to control costs while increasing revenues.

Competitive Strengths

We believe that we are well-positioned to compete in both the natural gas midstream and transportation and storage and propane industries based on the following strengths:

Our enhanced access to capital and financial flexibility will allow us to compete more effectively in acquiring assets and expanding our systems. We expect that our credit facilities and our recent financing transactions increases our financial flexibility and enhances our access to capital. We believe this will allow us to implement our operating strategies in a timely manner and more effectively compete in acquiring additional assets or expanding our existing systems.

Our experienced management team has an established reputation as highly-effective, strategic operators within our operating segments. In the past, the management teams of each of our operating segments have been successful in identifying and consummating strategic acquisitions that enhance our businesses. In addition, our management team has a substantial equity ownership in us and is motivated through performance-based incentive compensation programs to effectively and efficiently manage our business operations.

Midstream and Transportation and Storage Business Strengths

We have a significant market presence in each of our operating areas. We have a significant market presence in each of our operating areas, which are located in major natural gas producing regions of the United States. We expect the acquisition of Transwestern Pipeline will provide us with market presence in other prolific gas-producing regions of the western United States.

Our assets provide marketing flexibility through our access to numerous markets and customers. The combination of our Oasis Pipeline and our Southeast Texas System provides our 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, our 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, the HPL acquisition in January 2005, and the completion of the East Texas Pipeline

 

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system and the Fort Worth Basin pipeline, we have also increased our access to additional power plants, industrial users, municipalities, and co-operatives, and the added storage facilities add flexibility for fuel management services. The completion of the 42-inch pipeline project and other related projects will provide producers with firm capacity out of the Barnett Shale and other major producing areas to all major market hubs in Texas and numerous interstate pipelines. We also expect to provide producers with additional firm capacity once we complete the acquisition of Transwestern Pipeline.

Our Southeast Texas System has additional capacity, which provides opportunities for higher levels of utilization. We expect to connect new supplies of natural gas volumes by utilizing the available capacity on the Southeast Texas System. The available capacity also provides us with opportunities to extend the Southeast Texas System to additional natural gas producing areas, such as east Texas, through the East Texas Pipeline.

Our ability to bypass our La Grange processing plant reduces our commodity price risk. A significant benefit of our ownership of the Oasis Pipeline is that we can elect not to process natural gas at our 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, we are 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 us to sell the blended natural gas for a higher price than we would have been able to realize upon the sale of NGLs if we had to process the natural gas to extract NGLs.

The Houston Pipeline System enables us to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. The Bammel natural gas storage facility, acquired when we purchased the Houston Pipeline System, has 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, we are able to purchase physical natural gas and then sell financial contracts at a price sufficient to cover our 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. We believe our geographically diverse network of retail propane assets reduces our exposure to unfavorable weather patterns and economic downturns in any one geographic region, thereby reducing the volatility of our cash flows.

Experience in identifying, evaluating and completing acquisitions. We follow 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 reputation for quality service, and (4) own a high percentage of the propane tanks used by their customers. In addition, we attempt to capitalize on the reputations of the companies we acquire by maintaining local brand names, billing practices and employees, thereby creating a sense of business continuity which minimizes customer loss. We believe that this strategy has also helped to make us an attractive buyer for many propane acquisition candidates from a seller’s viewpoint.

Operations that are focused in areas experiencing higher-than-average population growth. We believe that our concentration in higher-than-average population growth areas provides a strong economic foundation for expansion through acquisitions and internal growth. We do not believe that we are more vulnerable than our competitors to displacement by natural gas distribution systems because the majority of our areas of operations are located in rural areas where natural gas is not readily available.

Low-cost administrative infrastructure. We are dedicated to maintaining a low-cost operating profile and have a successful track record of aggressively pursuing opportunities to reduce costs. Of our 3,890 full-time propane employees as of October 13, 2006, only 173, or approximately 4.5%, were general and administrative.

Decentralized operating structure and entrepreneurial workforce. We believe that our 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.

 

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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 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 materials produced at the wellhead are 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, in its 2006 annual outlook, total domestic consumption of natural gas is expected to increase by over 0.7% per annum, from an estimated 22.4 Tcf consumed in 2004 to 26.9 Tcf in 2030. During the five-year period ended December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, with average domestic production of approximately 18.9 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 rock 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 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 higher in carbon dioxide, hydrogen sulfide or certain 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 pipeline 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 Industry Overview

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 our wholesale operations, we sell propane principally to governmental agencies and industrial end-users.

 

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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. We compete 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, we believe 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. According to industry publications, propane accounts for 6 1/2% of household energy consumption in the United States.

In addition to competing with alternative energy sources, we compete 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 marketers and farm cooperatives. Most of our customer service locations compete with five or more marketers or distributors in their area of operations. 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. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers.

The wholesale propane business is highly competitive. For fiscal year 2006, our domestic wholesale operations (excluding M-P Energy Partnership) accounted for approximately 4.0% of our total gallons sold in the United States and approximately .86% of our gross profit. We do not emphasize wholesale operations, but believe that limited wholesale activities enhance our ability to supply our retail operations.

The Midstream and Transportation and Storage Segments

Competition

The business of providing natural gas gathering, transmission, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage segment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying 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 our marketing operations.

 

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Credit Risk and Customers

We have 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. We are diligent in attempting to ensure that we issue credit to credit-worthy customers. However, our purchase and resale of gas exposes us 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 our overall profitability.

During the year ended August 31, 2006, none of our customers individually accounted for more than 10% of midstream and transportation and storage segment revenues.

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. Currently we do not own any interstate natural gas transportation facilities, so FERC does not directly regulate any of our pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of our business and the market for our 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.

In connection with our announcement to acquire the Transwestern Pipeline, we will be regulated by the FERC as the Transwestern Pipeline transports natural gas in interstate commerce.

Intrastate Pipeline Regulation. Our 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 our 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.

Our 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 we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us 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.

 

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Sales of Natural Gas. Sales for resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates are subject to FERC regulation unless the gas is produced by the pipeline or affiliate. Under current federal rules, however, the price at which we sell 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 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 FERC. 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 we will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, our 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. 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 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 regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines in Texas and Louisiana that we believe 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 our gathering facilities could be 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.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our 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, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. Our Chalkley System is regulated as an intrastate transporter, and the Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. 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 the right of 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 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 allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design,

 

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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. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

As part of industry-wide inquiries into the natural gas market disruptions occurring around the times of the hurricanes of late 2005, we have participated in discussions with, and have provided information to, industry regulators concerning transactions by our subsidiaries during our fiscal 2006 first and second quarters. We believe, after due inquiry, that our transactions complied in all material respects with applicable rules and regulations. These regulatory inquiries have not yet been concluded. While we are unable to predict the final outcome of these inquiries, management believes it is probable that the industry regulators will require a payment in order to conclude the inquiries. Accordingly, management has provided an accrual as of August 31, 2006 for our best estimate of the payment amount that will be required to conclude these inquiries in a negotiated settlement process. We do not expect that any expenditures incurred in connection therewith in excess of the accrual provided as of August 31, 2006 will have a material impact on our financial condition, results of operations or liquidity in any future periods.

Pipeline Safety. The states in which we conduct 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 our gathering facilities from jurisdiction under that statute. The portions of our 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 our intrastate natural gas pipelines.

Propane Segment

Products, Services and Marketing

We distribute propane through a nationwide retail distribution network consisting of 442 customer service locations in 41 states. Our operations are concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States. We serve more than one million active customers. Historically, approximately two-thirds of our retail propane volumes and substantially all of our propane-related operating income is 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, we will reserve cash from peak periods for distribution to 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 our 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, which generally holds 2,500 to 3,000 gallons of propane, is loaded with propane from the storage tank. Propane is then delivered to the customer by the bobtail truck and pumped into a stationary storage tank on the customer’s premises. We also deliver propane to retail customers in portable cylinders. We also deliver 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.

We encourage our customers whose propane needs are temperature sensitive to implement a regular delivery schedule. Many of our 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. We also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances.

 

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Approximately 96% of the domestic gallons we sold in the fiscal year ended August 31, 2006 were to retail customers and 4% were to wholesale customers. Of the retail gallons we sold, approximately 54% were to residential customers, 31% were to industrial, commercial and agricultural customers, and 15% were to other retail users. Sales to residential customers in the fiscal year ended August 31, 2006 accounted for 52% of total domestic gallons sold but accounted for approximately 66% of our gross profit from propane sales. Residential sales have a greater profit margin and a more stable customer base than the other markets we serve. Industrial, commercial and agricultural sales accounted for 25% of our gross profit from propane sales for the fiscal year ended August 31, 2006, with all other retail users accounting for 9%. Additional volumes sold to wholesale customers contributed 1% of our gross profit from propane sales. No single customer accounts for 10% or more of revenues.

The propane business is very seasonal with weather conditions significantly affecting demand for propane. We believe that the geographic diversity of our operations helps to reduce our 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 our 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 our customers to remain with us due to the product being delivered pursuant to a regular delivery schedule and to our ownership as of August 31, 2006 of approximately 84% of the storage tanks utilized by our customers, which prevents fuel deliveries from competitors; and

 

  our historic ability to more than offset customer losses through internal growth of our 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 we operate can significantly affect the total volumes of propane that we sell and the margins realized thereon and, consequently, our 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

Our supplies of propane historically have been readily available from our supply sources. We purchase 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, 2006, Enterprise Products Operating L.P. (“Enterprise”) and Targa Liquids (“Targa”) provided approximately 27.0%, and 18.0% of our combined total propane supply, respectively. In addition, M-P Energy Partnership, a Canadian partnership in which our wholly-owned subsidiary, M.P. Oils, Ltd., owns a 60% interest procured 22.0% of our combined total propane supply during the fiscal year ended August 31, 2006. M-P Energy Partnership buys and sells propane for its own account and supplies propane to us for our northern United States operations. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010.

We believe that if supplies from Enterprise or Targa were interrupted we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Aside from Enterprise, Targa, and the supply procured by M-P Energy Partnership, no single supplier provided more than 10% of our total domestic propane supply during the fiscal year ended August 31, 2006. We believe that our diversification of suppliers will enable us to purchase all of our supply needs at market prices without a material disruption of our operations if supplies are interrupted from any of our 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.

Except for Titan’s supply agreement, we typically enter 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 at 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. We receive our supply of propane predominately through railroad tank cars and common carrier transport.

 

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Because our profitability is sensitive to changes in wholesale propane costs, we generally seek to pass on increases in the cost of propane to customers. We have 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 we will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, our profitability will be sensitive to changes in wholesale propane prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

We lease space in larger storage facilities in Michigan, Arizona, New Mexico, and Texas, and smaller storage facilities in other locations, and have the opportunity to use storage facilities in additional locations when we “pre-buy” product from sources having such facilities. We believe that we have adequate third party storage to take advantage of supply purchasing advantages as they may occur from time to time. Access to storage facilities allows us 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. We rely on 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, we believe that our pricing methods will permit us to respond to changes in supply costs in a manner that protects our gross margins and customer base; to the extent such protection is possible. In some cases, however, our ability to respond quickly to cost increases could occasionally cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.

Billing and Collection Procedures

Customer billing and account collection responsibilities for our propane operations are retained at the local customer service locations. We believe 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, our 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, lower net income or net losses during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather-sensitive.

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 the protection of the environment. These laws and regulations can impair our business activities that affect the environment in many ways, such as:

 

  restricting the way we can release materials or waste products into the air, water, or soils;

 

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  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 us for pollution resulting from our 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. We have 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 our operations, and we cannot assure you that we will not incur significant costs and liabilities if such upsets, releases, or spills were to occur. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, 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 substance under CERCLA, we will generate materials in the course of our operations that may be regulated as hazardous substances. We 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 our operations, we 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.

We currently own or lease, and have 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 we 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 us, 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 our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we 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 us 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. We have not received any follow-up correspondence from EPA on the matter since our acquisition of the predecessor company in 2001. In addition, through our acquisitions of ongoing businesses, we are currently involved in several remediation projects that have cleanup costs and related liabilities. As of August 31, 2006 an accrual of $1.4 million was recorded in our consolidated balance sheet to cover estimated environmental liabilities

 

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including certain matters assumed in connection with our acquisition of HPL. We have also recorded a receivable of $0.4 million to account for the predecessor owner’s share of certain environmental liabilities of ETC OLP. In addition, we recorded an accrual of $3.0 million in connection with our acquisition of Titan for the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors.

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 our systems or facilities could result in fines or penalties, as well as significant remedial obligations. We believe that we are in substantial compliance with the Clean Water Act. We currently expect to incur costs of approximately $0.1 million over the next year to upgrade or modify certain facilities as required under our 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 us 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 us to civil and criminal enforcement actions. We received a state-issued “Pipeline Facilities” air emissions permit on June 30, 2005 for our Prairie Lea Compressor Station in Caldwell County, Texas, which historically has been designated as a “grandfathered facility” and, thus, was excluded from state air emissions permitting requirements. In order to comply with the terms of this permit and associated regulations requiring specified reductions in nitrogen oxides or “NOx” emissions by March 1, 2007, we are planning to modify the compressor engines at the facility during 2006, at an estimated cost of $2.0 million. In addition, we are currently pursuing agency-approved baseline monitoring of NOx emissions from our Katy Compressor Station in Harris County, Texas, which is in a non-attainment area for ozone. Once we develop this NOx baseline, we have been planning to purchase a sufficient amount of NOx emission allowances that would allow the facility to continue at its current level of operation in the non-attainment area, at an estimated cost of $2.3 million. These plans are subject to possible change however, as the non-attainment area is currently transitioning from a 1-hour ozone non-attainment area to an 8-hour ozone non-attainment area, which transition we expect will result in the adoption of further regulations that will perhaps change the extent to which NOx emissions reductions may be required.

Our 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 the DOT. While we believe that our 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 our 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. We estimate that compliance with these rules will result in capital costs of $21.3 million during the period between the remainder of calendar year 2006 to 2008 as well as operating and maintenance costs of $24.8 million during the three year period.

We are 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 hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our 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 we operate. In some states these laws are administered by state agencies, and in others they are

 

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administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage, and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

Employees

As of October 13, 2006, we employ 604 people to operate our midstream and transportation and storage segments. We employ 3,900 full-time employees (including 10 which are considered partnership employees), of whom 70 are represented by labor unions, to operate our propane segments. We believe that our relations with our employees are satisfactory. Historically, our propane operations hire seasonal workers to meet peak winter demands.

SEC Reporting

We electronically file certain documents with the SEC. We file annual reports on Form 10-K; quarterly reports on Form 10-Q; current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

We provide electronic access to our periodic and current reports on our Internet website, www.energytransfer.com, free of charge. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC.

ITEM 1A. RISK FACTORS

An investment in our securities involves a high degree of risk. You should carefully consider the following risk factors included below, together with all of the other information included in, or incorporated by reference into, this report in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our Common Units could decline and you could lose all or part of your investment.

Risks Inherent in an Investment in Us:

Our only assets are our partnership interests, including the incentive distribution rights, in ETP and, therefore, our cash flow is 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 depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 

  the amount of natural gas transported in the Oasis Pipeline and in its gathering systems;

 

  the level of throughput in its processing and treating operations;

 

  the fees it charges and the margins it realizes for its services;

 

  the price of natural gas;

 

  the relationship between natural gas and NGL prices;

 

  the weather in our operating areas;

 

  the cost of the propane it buys for resale and the prices it receives for its propane;

 

  the level of competition from other propane companies and other energy providers;

 

  the level of its operating costs;

 

  prevailing economic conditions; and

 

  the level of ETP’s hedging activities.

 

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In addition, the actual amount of cash that ETP will have available for distribution will also depend on other factors, such as:

 

  the level of capital expenditures it makes;

 

  the cost of acquisitions, if any;

 

  the levels of any margin calls that result from changes in commodity prices;

 

  its debt service requirements;

 

  fluctuations in its working capital needs;

 

  its ability to make working capital borrowings under its credit facilities to make distributions;

 

  restrictions on distributions contained in its debt agreements; and

 

  the amount, if any, of cash reserves established by its General Partner in its discretion for the proper conduct of ETP’s business.

Because of these factors, we cannot guarantee that ETP will have sufficient available cash to pay a specific level of cash distributions to its Partners.

Furthermore, you should be aware that 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 make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income. Please read “Risks Related to Energy Transfer Partners’ Business” included in this Item 1A for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.

We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.

The source of our earnings and cash flow is cash distributions from ETP. Therefore, the amount of distributions we are currently 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, 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;

 

  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 current 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.

 

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Affiliates of our General Partner own approximately 75.0% 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.

Our affiliates own approximately 75.0% of our outstanding Common Units on a fully diluted basis. In addition, some of these owners are members of the Board of Directors of our General Partner. Because these owners have the ability to amend our Partnership Agreement and change our cash distribution policy, 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 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 158 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 entitled.

Our direct and indirect ownership of 100% of the incentive distribution rights in ETP (50% prior to November 1, 2006), 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 distribution levels. The amount of the cash distributions that we received from ETP during our fiscal year 2006 related to our ownership interest in the incentive distribution rights has increased at a more rapid rate than the amount 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 those assets.

Our increased consolidated debt level and our debt agreements and those of our subsidiaries may limit our ability to make distributions to Unitholders and may limit the distributions we receive from ETP and our future financial and operating flexibility.

As of August 31, 2006, we had approximately $3.2 billion of consolidated debt outstanding. Our level of indebtedness affects our operations in several ways, including, among other things:

 

  a significant portion of our and ETP’s cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

 

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  covenants contained in our and ETP’s existing debt arrangements require us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

 

  our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

 

  we may be at a competitive disadvantage relative to similar companies that have less debt;

 

  we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

 

  failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of August 31, 2006, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of August 31, 2006, we had approximately $3.2 billion of consolidated debt, of which approximately $1.4 billion was at fixed interest rates and approximately $1.8 billion was at variable interest rates, after giving effect to our existing interest swap arrangements. We may enter into additional interest rate swap arrangements. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.

The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile.

The credit and business risk profiles of our General Partner or owners of a general partner may be factors in credit evaluations of us as a master limited partnership. This is because our General Partner can exercise significant influence over our business activities, including our cash distributions and, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our General Partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.

We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:

 

  the current proportionate ownership interest of our Unitholders in us will decrease;

 

  the amount of cash available for distribution on each Common Unit or partnership security may decrease;

 

  the relative voting strength of each previously outstanding Common Unit may be diminished; and

 

  the market price of our Common Units may decline.

In addition, ETP may sell an unlimited number of limited partner interests without the consent of its Unitholders which will dilute existing interests of its Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP will have essentially the same effects as detailed above.

 

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The market price of our Common Units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing Unitholders.

Sales by any of our existing Unitholders of a substantial number of our units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our 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 unit price in the future.

Control of our General Partner 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.

Our General Partner has only 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 and legal 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 other than through our shared services agreement with ETP. We do not currently have a plan for identifying a successor to Mr. McReynolds in the event that he retires, dies or becomes disabled. If Mr. McReynolds ceases to serve as the President and Chief Financial Officer of our General Partner for any reason, we would be without executive management other than through our shared services agreement with ETP until one or more new executive officers are selected by the board of directors of our General Partner. As a consequence, the loss of Mr. McReynolds’ services could have a material negative impact on the management of our business.

Moreover, we rely 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 ETP’s 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 and transportation and storage businesses 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 a shared services agreement allocate 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. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

An increase in interest rates may cause the market price of our units to decline.

Like all equity investments, an investment in our 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 units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our 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

 

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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.

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 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 Securities and Exchange 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.

If Energy Transfer Partners GP, L.P. (“ETP GP, LP”) withdraws or is removed as ETP’s General Partner, then we would lose control over the management and affairs of Energy Transfer Partners, the risk that we would be deemed an investment company under the Investment Company Act of 1940 would be exacerbated and our indirect ownership of the General Partner interests and 100% of the incentive distribution rights in ETP could be cashed out or converted into ETP Common Units at an unattractive valuation.

Under the terms of ETP’s Partnership Agreement, ETP GP, LP will be deemed to have withdrawn as General Partner if, among other things, it:

 

  voluntarily withdraws from the partnership by giving notice to the other partners;

 

  transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s Partnership Agreement;

 

  makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or

 

  dissolves itself under Delaware law without reinstatement within the requisite period.

In addition, ETP GP, LP can be removed as ETP’s General Partner if that removal is approved by Unitholders holding at least 66 2/3% of ETP’s outstanding units (including units held by ETP GP, LP and its affiliates).

If ETP GP, LP withdraws from being ETP’s General Partner in compliance with ETP’s Partnership Agreement or is removed from being ETP’s General Partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor general partner to purchase its general partner interests, incentive distribution rights and limited partner interests in ETP for fair market value. If ETP GP, LP withdraws from being ETP’s General Partner in violation of ETP’s Partnership Agreement or is removed from being ETP’s General Partner in circumstances where a court enters a judgment that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s General Partner, and the successor general partner does not exercise its option to purchase the general partner interests, incentive distribution rights and limited partner interests held by ETP GP, LP in ETP for fair market value, then the general partner interests and incentive distribution rights held by ETP GP, LP in ETP could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP, LP would lose control over the management and affairs of ETP, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act of 1940. In addition, our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP, to which a significant portion of the value of our Common Units is currently attributable, could be cashed out or converted into ETP Common Units at an unattractive valuation.

 

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Our Common Unit price may be volatile, and a trading market that will provide you with adequate liquidity may not be sustained.

Prior to our IPO there was no public market for our Common Units. An active market for our Common Units may not be sustained. The initial public offering price of our Common Units was determined by negotiations between us and the underwriters, based on several factors that we discuss in the “Underwriting” section of our prospectus. This price may not be indicative of the market price for our Common Units after the initial public offering. The market price of our Common Units could be subject to significant fluctuations 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 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 our Common Units and limit the number of investors who are able to buy our 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.

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.

 

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Future sales of the ETP Common Units we own or other limited partner interests in the public market could reduce the market price of our Unitholders’ limited partner interests.

As of August 31, 2006, we owned 36,413,840 Common Units of ETP. If we were to sell and/or distribute our ETP Common Units to the holders of our equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of ETP’s outstanding Common Units and our receipt of distributions.

Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.

Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.

An impairment of goodwill and intangible assets could reduce our earnings.

At August 31, 2006, our consolidated balance sheet reflected $634.0 million of goodwill and $185.7 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

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.

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;

 

  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.

 

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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.

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.

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 it and its affiliates have incurred 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.

 

  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.

Our reimbursement of fees and expenses of our General Partner will limit our cash available for distribution.

Our General Partner may make expenditures on our behalf for which it will seek reimbursement from us. In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner. To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.

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:

 

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  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.

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. Affiliates of our General Partner own approximately 75.0% of our Common and Class B Units.

In the event we acquire an interstate pipeline that is subject to rate regulation by the Federal Energy Regulatory Commission and 15% or more of our outstanding Common Units and Class B Units, in the aggregate, are held by persons who are not Eligible Holders, Common Units held by persons who are not Eligible Holders will be subject to the possibility of redemption at the then-current market price.

In the event we acquire an interstate pipeline that is subject to rate regulation of the Federal Energy Regulatory Commission, or FERC, our General Partner will have the right under our Partnership Agreement to institute procedures, by giving notice to each of our Unitholders, that would require transferees of Common Units and, upon the request of our General Partner, existing holders of our Common Units to certify that they are Eligible Holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s rate base upon which tariffs may be established under FERC rate-making policies applicable to entities that pass-through their taxable income to their owners. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented and 15% or more of our outstanding Common Units and Class B Units, in the aggregate, are held by persons who are not Eligible Holders, we will have the right to redeem the units held by persons who are not Eligible Holders at the then-current market price. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our General Partner.

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.

 

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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.

Risks Related to Energy Transfer Partners’ Business

Since our cash flows consist exclusively of distributions from ETP, risks to ETP’s business are also risks to us. We have set forth below risks to ETP’s business, the occurrence of which could have a negative impact on ETP’s financial performance and decrease the amount of cash it is able to distribute to us, thereby impacting the amount of cash that we are able to distribute to our Unitholders.

The profitability of ETP’s midstream and transportation and storage businesses is, to an extent, dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors 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 and at ETP’s Houston Pipeline 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 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.

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 an 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 ETP 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 ETP expects this volatility to continue. For example, during ETP’s fiscal year ended August 31, 2006, the NYMEX settlement price for the prompt month contract ranged from a high of $15.38 per MMBtu to a low of $5.52 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during ETP’s fiscal year ended August 31, 2006 ranged from a high of approximately $1.18 per gallon to a low of approximately $0.87 per gallon.

Average realized natural gas sales prices for the twelve months ended August 31, 2006 exceeded ETP’s historical realized natural gas prices. For example, ETP’s average realized natural gas price increased $1.61, or 25%, from $6.43 per MMBtu for the year ended August 31, 2005 to $8.04 per MMBtu for the year ended August 31, 2006. On September 30, 2006, the NYMEX settlement price for October 2006 natural gas deliveries was $4.20 per MMBtu, which was 48% lower than the average natural gas price for the year ended August 31, 2006. Natural gas prices are subject to significant fluctuations, and ETP cannot assure you that natural gas prices will remain at the high levels recently experienced.

 

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ETP’s Oasis Pipeline, East Texas Pipeline System, ET Fuel System and Houston Pipeline System receive fees for transporting natural gas for its customers. Although a significant amount of the pipeline capacity of the East Texas Pipeline System 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. ETP’s fuel retention fees are also directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase ETP’s fuel retention fees, and decreases in natural gas prices tend to decrease its fuel retention fees.

The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s 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.

The use of derivative financial instruments could result in material financial losses by ETP.

From time to time, ETP has sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms and by the activities ETP conducts in its trading operations. To the extent that ETP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change in ETP’s favor. In addition, even though monitored by management, ETP’s hedging and trading activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed.

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 ETP’s 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 not be able 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 ETP’s 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 consist of its 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.

 

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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 is collectively referred 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 it 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 ETP’s 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 ETP 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 natural decline rate in ETP’s 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 ETP’s 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 ETP operates.

ETP may not be able 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 its ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. ETP regularly considers and enters into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that ETP believes will present opportunities to realize synergies and increase its cash flow.

Consistent with ETP’s acquisition strategy, management is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP management’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. ETP cannot assure you that its 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. Inability to execute its growth strategy may materially adversely impact the market price of ETP’s 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 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 ETP’s Unitholders, including the Parent Company.

 

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In addition, ETP may be unable to make accretive acquisitions for any of the following reasons, among others:

 

  because ETP is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

  because ETP is unable to raise financing for such acquisitions on economically acceptable terms; or

 

  because ETP 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.

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 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 ETP 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 ETP 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 ETP management’s attention from other business concerns; or

 

  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 ETP will consider.

ETP’s actual construction, development and acquisition costs could exceed forecasted amounts.

ETP may have significant expenditures for the development and construction of energy infrastructure assets, including some construction and development projects with significant technological challenges. ETP may not be able to complete its projects at the costs estimated at the time of each project’s initiation.

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.

As of ETP’s fiscal year ended August 31, 2006, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied ETP with approximately 44% 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 ETP, ETP would be adversely affected unless it was 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 System and ET Fuel System.

ETP has entered into 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 is referred 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

 

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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 ETP was 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, ETP 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. 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 ETP operate 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 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, ETP’s 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 ETP 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 TRCC–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 the 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.

 

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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 its 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 its 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.

ETP may incur substantial environmental costs and liabilities because the underlying risks 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 its 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 its 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 ETP’s 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 ETP’s 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 ETP’s 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. ETP’s 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 System 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. Some of ETP’s competitors may have greater financial resources and access to larger natural gas supplies than it does.

The acquisition of the Houston Pipeline System increased the number of interstate pipelines and natural gas markets to which ETP has access and expanded its principal areas of competition to areas such as southeast Texas and the

 

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Texas Gulf Coast. As a result of ETP’s expanded market presence and diversification, ETP faces 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 may have greater financial resources and access to larger natural gas supplies than ETP 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, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane 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 ETP’s control and require the expenditure of significant amounts of capital that ETP 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 ETP’s 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 the Parent Company.

The risks of nonpayment and nonperformance by ETP’s customers are 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 substantial increase in the nonpayment and nonperformance by ETP’s customers could reduce its ability to make distributions to its Unitholders, including the Parent Company.

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, ETP 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 ETP serves.

For ETP’s fiscal year ended August 31, 2006, approximately 40% of its sales of natural gas 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 ETP’s 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 they have 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 ETP’s 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 ETP’s 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, ETP estimated that compliance with this final rule for its existing transportation assets will result in capital costs of $21.3 million during the period between the remainder of calendar year 2006 to 2008, as well as operating and maintenance costs of $24.8 million during that period. 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.

Since weather conditions may adversely affect demand for propane, ETP’s financial conditions may be 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 results of operations 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 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 ETP sells and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including periods of unseasonably cold or hot periods or dry weather conditions which may impact agricultural operations.

 

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A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect its cash flow and, accordingly, affect the market price of ETP’s Common Units.

Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including the Parent Company and, accordingly, adversely affect the market price of ETP’s Common Units.

ETP believes that it maintains adequate insurance coverage, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at ETP’s facilities could adversely affect its business, results of operations, cash flows and financial condition.

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on ETP’s facilities or pipelines or those of its customers could have a material adverse effect on ETP’s business.

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect ETP’s profit margins.

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, ETP’s profitability 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 ETP pays for it 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 ETP’s gross profits and could, if continued over an extended period of time, reduce demand by encouraging ETP’s retail customers to conserve their propane usage 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 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 its profits.

 

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Some of ETP’s propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to ETP’s 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 the 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 ETP management’s estimates 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 its profitability.

ETP is dependent on its principal propane suppliers, which increases the risk of an interruption in supply.

During fiscal 2006, ETP purchased approximately 27% of its propane from Enterprise Products Operating L.P., approximately 18% from Targa Liquids, and approximately 22% of its propane from M-P Energy Partnership, the Canadian partnership in which ETP owns a 60% interest. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. If 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 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 ETP uses, 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.

Tax Risks to Common Unitholders

The IRS could treat us or ETP as a corporation for tax purposes, which would substantially reduce the cash available for distribution to Unitholders.

The anticipated after-tax economic benefit of an investment in our Common 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 or any other matter affecting us. The value of our investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.

 

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and we would likely pay additional state income taxes as well. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because an additional, material tax would be imposed upon us in that case, our cash available for distribution to Unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the available cash distributions to the Unitholders, likely causing a substantial reduction in the value of our Common 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.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that causes us to be treated as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be adjusted to reflect that impact on us.

A successful IRS contest of the federal income tax positions we or ETP takes may adversely affect the market for our Common Units or ETP Common Units and the costs of any contest will reduce cash available for distributions 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.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income. In such case, Unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.

Only calendar year taxpayers may become partners.

Only calendar year taxpayers may purchase Common Units. Any Unitholder who is not a calendar year taxpayer will not be admitted to Energy Transfer Partners, L.P. as a partner, will not be entitled to receive distributions or federal income tax allocations from Energy Transfer Partners, L.P. and may only transfer these Common Units to a purchaser or other transferee.

 

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Tax gain or loss on disposition of Common Units could be different than expected.

Unitholders who sell Common Units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those Common Units. Prior distributions in excess of the total net taxable income allocated for a Common Unit that decreased a Unitholder’s tax basis in that Common Unit will, in effect, become taxable income to the Unitholder if the Common Unit is sold at a price greater than the Unitholder’s tax basis in that Common Unit, even if the price is less than his original cost. A substantial portion of the amount the Unitholder realizes, whether or not representing gain, will likely be ordinary income to the Unitholder. Should the IRS successfully contest some positions we take, a Unitholder could recognize more gain on the sale of Common Units than would be the case under those positions, without the benefit of decreased income in prior years. Also, Unitholders who sell Common Units may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning Common Units that may result in adverse tax consequences to them.

Investment in Common Units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income”. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our Common Units.

We will treat each purchaser of Common 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 the units.

Because we cannot match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that do 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 the Unitholder’s sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to the Unitholder’s tax returns.

Unitholders likely will be subject to state and local taxes in states where they do not live as a result of an investment in the units.

In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local 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 now or in the future, even if they do not live in any of those jurisdictions. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in us.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all Unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Substantially all of our pipelines, which are located in Texas and Louisiana, 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

 

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subject to prior liens that have not been subordinated to the right-of-way grants. We have 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, properties on which our pipelines were built were purchased in fee.

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe 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 our business.

We own two office buildings for our executive offices in Dallas, Texas and one office building in Helena, Montana for the administration of our propane operations. We also lease office facilities in Houston, Texas, San Antonio, Texas, and Tulsa, Oklahoma. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

We operate bulk storage facilities at 442 customer service locations for our propane operations. We own substantially all of these facilities and have entered into long-term leases for those that we do not own. We believe that the increasing difficulty associated with obtaining permits for new propane distribution locations makes our high level of site ownership and control a competitive advantage. We own approximately 48.0 million gallons of aboveground storage capacity at our various propane plant sites and have leased an aggregate of approximately 35.3 million gallons of underground storage facilities in Michigan, Arizona, New Mexico, and Texas and smaller storage facilities in other locations. We do 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).

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, 2006, we utilized approximately 68 transport truck tractors, 68 transport trailers, 15 railroad tank cars, 1,772 bobtails and 2,831 other delivery and service vehicles, all of which we own. As of August 31, 2006, we owned approximately 1,135,800 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 the obligations of HOLP to its banks and the holders of its notes.

We utilize a variety of trademarks and trade names in our propane operations that we own or have secured the right to use, including “Heritage Propane” and “Titan Propane.” These trademarks and trade names have been registered or are pending registration before the United States Patent and Trademark Office or the various jurisdictions in which the trademarks or trade names are used. We believe that our strategy of retaining the names of the companies we have acquired has maintained the local identification of these companies and has been important to the continued success of these businesses. Some of our 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, Coast Gas, Empiregas, Flame Propane, Graves Propane, Synergy Gas. We regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our 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, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have 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 our properties or the operations of our business.

 

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ITEM 3. LEGAL PROCEEDINGS

Although our Operating Partnerships may, from time to time, be involved in litigation and claims arising out of operations in the normal course of their businesses, such Operating Partnerships are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against our Operating Partnerships, or contemplated to be brought against our Operating Partnerships, under the various environmental protection statutes to which it they are subject.

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 Bank of America’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). At issue are matters relating to the ownership and certain rights to use the 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.

HOLP received favorable final judgment with respect to the SCANA litigation on all four claims on October 21, 2004, and received $7.7 million in net settlement proceeds on June 1, 2006 (see Note 10 to our consolidated financial statements).

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, and in the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, may have a significant effect on the results of operations for a single period. However, we believe that such matters will not have a material adverse effect on our financial position. 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, we accrue the related deductible.

As of August 31, 2006 and 2005, an accrual of $32,148 and $1,120, respectively, was recorded as accrued and other current liabilities on our consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters. (See Note 10 to our consolidated financial statements.)

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

 

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Parent Company

Market Price of and Distributions on the Common Units and Related Unitholder Matters

Beginning in February 2006 the Parent Company’s Common Units were listed on the New York Stock Exchange under the symbol “ETE”. The following table sets forth, for the periods indicated, the high and low sales prices per Common Unit, as reported on the New York Stock Exchange Composite Transaction Tape, and the amount of cash distributions paid per Common Unit since the Parent Company’s initial public offering in February 2006.

 

     Price Range   

Cash

Distribution (1)

2006 Fiscal Year

   High    Low   

Fourth Quarter Ended August 31, 2006

   $ 27.16    $ 24.98    $ 0.3125

Third Quarter Ended May 31, 2006

   $ 27.65    $ 21.41    $ 0.2375

Period Ended February 28, 2006 (2)

   $ 23.29    $ 21.50    $ 0.0578

(1) Distributions are shown in the quarter with respect to which they were declared. For each of the indicated quarters for which distributions have been made, an identical per unit cash distribution was paid on any units subordinated to our Common Units outstanding at such time. Please see “Cash Distribution Policy” for a discussion of our policy regarding the payment of distributions.
(2) High and low for the period ended February 28, 2006 represents the period from February 3, 2006 (the IPO date) to February 28, 2006.

Description of Units

As of November 27, 2006, there were approximately 21,745 individual Common Unitholders, which includes Common Units held in street name. Common Units and Class B Units represent limited partner interest in the Partnership’s Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”) that entitle the holders to the rights and privileges specified in the Partnership Agreement.

Common Units. As of August 31, 2006, we had 124,360,520 Common Units outstanding, of which 51,866,382 were held by the public; 1,893,175 were held by our officers and directors. As of such date, the Common Units represent an aggregate 97.48% limited partner interest in us. Our General Partner owns an aggregate .54% General Partner interest in us and the Class B Units (discussed below) represent an aggregate 1.98% interest in us. Our Common Units are registered under the Securities Exchange Act of 1934, as amended and are listed for trading on the New York Stock Exchange (the “NYSE”). Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

Class B Units. As of August 31, 2006, we had 2,521,570 Class B Units outstanding, all of which are held by FEM Group, LP (see Item 11 – “Executive Compensation”). The Class B Units were issued to this entity in conjunction with the February 8, 2006 closing of the IPO. Each Class B Unit represents a limited partner interest in the Partnership and is convertible into a Common Unit on a one-for-one basis at the election of the holder.

Class C Units. See Note 17 to our consolidated financial statements for a discussion of our Class C Units issued on November 1, 2006.

Parent Company Cash Distribution Policy

General. The Parent Company will distribute all of its “Available Cash” to its Unitholders and its General Partner within 50 days following the end of each fiscal quarter.

 

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Definition of Available Cash. Available Cash is defined in the Parent Company’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 to:

 

  provide for the proper conduct of its business;

 

  comply with applicable law or any debt instrument or other agreement; and

 

  provide funds for distributions to Unitholders and its General Partner in respect of any one or more of the next four quarters.

The total amount of distributions declared for the year ended August 31, 2006 for Limited Partners (previous owners), Common Units, Class B Units and General Partner interests totaled $34.0 million, $65.9 million, $0.7 million, and $0.6 million, respectively. All such distributions were made from Available Cash.

The total amount of distributions declared by the Parent Company relating to the years ended August 31, 2006 and 2005 is as follows:

 

     2006    2005

Limited Partners -

     

Limited Partners (a)

   $ 34,010    $ 666,751

Common Units

     65,905      —  

Class B Units

     745      —  

General Partner

     599      4,861
             

Total distributions declared

   $ 101,259    $ 671,612
             

(a) Distributions to Limited Partners represent distributions to the previous owners of the Parent Company limited partner interests prior to its Initial Public Offering in February 2006.

Securities Authorized for Issuance Under Equity Compensation Plans

Please see Item 12 – “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” of this annual report.

Changes in Securities and Recent Sales of Unregistered Securities

On November 1, 2006, we issued 83,148,900 ETE Class C Units to ETI in exchange for the remaining 50% Class B limited partner interests in ETP GP held by ETI.

Issuer Purchases of Equity Securities

Units repurchased by the Parent Company during the fourth quarter of 2006 are as follows:

 

Period

   (a) Total Number
of Shares (or
Units) Purchased
   (b) Average
Price Paid per
Share (or Unit)
   (c) Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plan or Programs
   (d) Maximum Number
(or Approximate Dollar
Value) of Shares (or
Units) that May Yet Be
Purchased Under the
Plan or Programs

June 1, 2006 through June 30, 2006

   —        —      —      —  

July 1, 2006 through July 31, 2006

   9,642,757    $ 24.66    —      —  

August 1, 2006 through August 31, 2006

   —        —      —      —  
                     

Total

   9,642,757    $ 24.66    —      —  
                     

In July 2006, the Parent Company agreed to repurchase 9,642,757 of its Common Units in an unsolicited offer from a former Unitholder. The unit price paid approximated the closing date market price discounted at 5%. The Common Units that were repurchased were retired and canceled.

ITEM 6. SELECTED FINANCIAL DATA

Currently, the Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships; thus, the table below reflects the consolidated operations of the Parent Company including the operations of ETP and its consolidated subsidiaries, except as indicated below.

 

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Although Heritage Propane Partners, L.P. was the surviving parent entity for legal purposes in the Energy Transfer Transactions, ETC OLP was the acquirer for accounting purposes. As a result, following the Energy Transfer Transactions in January 2004, the historical financial statements of ETC OLP for periods prior to the closing of the Energy Transfer Transactions became our historical financial statements. ETC OLP was formed on October 1, 2002 and has an August 31 year-end. ETC OLP’s predecessor entities had a December 31 year-end.

In April 2005, we sold the Elk City System and accounted for the sale as discontinued operations. As such, the results presented for the period from October 1, 2002 to August 31, 2004 below have been restated to account for the results of the Elk City System in discontinued operations.

ETC OLP’s historical financial information for periods prior to October 1, 2002 has been derived from the historical financial statements of Aquila Gas Pipeline. Prior to October 1, 2002, Aquila Gas Pipeline owned the Southeast Texas System, the Elk City System and a 50% equity interest in Oasis Pipe Line. All of these assets were acquired by ETC OLP effective on October 1, 2002.

The financial information below for Aquila Gas Pipeline as of and for the nine months ended September 30, 2002 and as of and for the year ended December 31, 2001 and as of September 30, 2002 and December 31, 2001 has been derived from the audited consolidated financial statements of Aquila Gas Pipeline, which are not included in this report, but were included in previous filings.

The selected historical financial data should be read in conjunction with the financial statements of Energy Transfer Equity, L.P. included elsewhere in this report and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The amounts in the table below, except per unit data, are in thousands.

 

     Aquila Gas Pipeline     Energy Transfer Equity, L.P.  
    

Year

Ended

December 31,

2001

   

Nine Months

Ended

September 30,

2002

   

Eleven Months

Ended

August 31,

2003 (a)

    Year Ended August 31,  
         2004     2005     2006  

Statement of Operations Data:

            

Revenues

            

Midstream segment

   $ 1,813,850     $ 933,099     $ 899,086     $ 1,880,663     $ 3,246,772     $ 4,223,544  

Transportation and storage segment

     —         —         41,500       113,938       2,608,108       5,013,224  

Eliminations

     —         —         (9,559 )     (27,798 )     (471,255 )     (2,359,256 )

Propane segments

     —         —         —         376,689       778,306       973,844  

Other segment

     —         —         —         3,465       6,867       7,740  
                                                

Total revenues

     1,813,850       933,099       931,027       2,346,957       6,168,798       7,859,096  

Gross margin

     98,589       53,035       105,589       365,533       787,283       1,290,780  

Depreciation and amortization

     30,779       22,915       11,870       56,242       105,751       129,636  

Operating income

     42,990       2,862       55,501       130,806       297,921       575,540  

Interest expense

     6,858       3,931       12,453       41,217       101,061       150,646  

Gain on Energy Transfer Transactions

     —         —         —         395,253       —         —    

Minority interests in income from Continuing Operations

     —         —         —         (35,164 )     (96,946 )     (303,752 )

Income from continuing operations before income tax expense

     41,161       4,272       44,673       449,551       104,849       130,155  

Income tax expense (benefit)(b)

     15,403       (467 )     4,432       2,792       4,397       23,015  

Income from continuing operations

     25,758       4,739       40,241       446,759       100,452       107,140  

Basic income from continuing operations per limited partner unit (c)

     —         —         0.47       4.54       0.89       0.80  

Diluted income from continuing operations per unit (c)

     —         —         0.30       3.35       0.75       0.79  

Cash distribution per unit

     —         —         .03       1.36       2.66       2.56  

Balance Sheet Data (at period end):

            

Current assets

     144,396       116,831       223,897       481,868       1,453,730       1,302,736  

Total assets

     633,260       601,528       604,140       2,865,191       4,905,672       5,924,141  

Current liabilities

     194,816       144,076       169,967       404,917       1,244,785       1,020,787  

Long-term debt (less current maturities)

     66,250       66,250       196,000       1,071,158       2,275,965       3,205,646  

Stockholders’ equity/Partners’ capital (deficit)

     249,520       254,259       182,631       368,325       (88,137 )     45,751  

Other Financial Data:

            

Cash flow provided by operating activities

     65,198       12,987       70,675       122,098       38,133       310,782  

Cash flow used in investing activities

     (20,727 )     (487 )     (341,258 )     (731,831 )     (1,131,117 )     (1,244,406 )

Cash flow provided by (used in) financing

    activities

     (44,471 )     (12,500 )     325,655       637,513       1,043,591       926,369  

Capital expenditures

            

Maintenance and growth

     23,944       5,486       11,914       109,688       196,459       680,164  

Acquisition

     —         —         340,187       622,929       1,131,844       586,185  

 

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(a) On December 27, 2002, ETC OLP purchased the remaining 50% of Oasis Pipe Line. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After this date, Oasis Pipe Line’s results of operations are consolidated with ETC OLP as a wholly-owned subsidiary.
(b) As a partnership, we are not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings 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.
(c) Basic income from continuing operations per limited partner unit is computed by dividing income from continuing operations, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted income from continuing operations per limited partner unit is computed by dividing income from continuing operations (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per unit computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s unit-based compensation plans had been issued during the respective periods. Such units have been determined based on the treasury stock method.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in Item 1A “Risk Factors” included in this report.

Currently, the Parent Company’s business operations are conducted only through ETP’s wholly-owned subsidiary Operating Partnerships. ETC OLP is a Texas limited partnership engaged in midstream and transportation and natural gas storage operations. HOLP is a Delaware limited partnership engaged in retail and wholesale propane operations. Titan is a Delaware limited partnership engaged in retail propane operations. ETC OLP, HOLP and Titan are collectively referred to as “the Operating Partnerships”.

The following is a discussion of our historical financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in Item 8 in this report.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” shall mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners G.P., L.P. (“ETP GP”), the General Partner of ETP, and ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). References to “the Parent Company” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.

Overview

Parent Company – Energy Transfer Equity, L.P.

Currently, the Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Partnerships.

 

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In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

General

Our primary objective is to increase the level of our cash distributions to our partners over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amount of cash that we will have available for distribution will primarily depend on the amount of cash we generate from operations.

During the past several years we have been successful in completing several transactions that have been accretive to our Unitholders. First and foremost was the combination of the retail propane operations of HOLP and the midstream and transportation and storage operations of ETC OLP in January 2004. Subsequent to the combination, we have made numerous acquisitions in both the natural gas and propane operations, including the acquisition of the ET Fuel System, Houston Pipeline System (“HPL”) and Titan. We have also recently announced the pending acquisition of Transwestern Pipeline. Concurrently, we have also made significant investments in internal growth projects which we believe will provide additional cash flow to our Unitholders in years to come.

ETP’s Operations

Midstream and Transportation and Storage Segments

Through ETC OLP, we own the largest intrastate pipeline system in the United States with interconnects to major consumption areas throughout the United States. The midstream and transportation and storage operations accounted for approximately 99% of our consolidated operating income for the year ended August 31, 2006.

Our midstream segment results are derived primarily from margins we realize for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems, processed at our processing and treating facilities, and the volumes of NGLs processed at our facilities. We also market natural gas on our pipeline systems in addition to other pipeline systems to realize incremental revenue on gas purchased, increase pipeline utilization and provide other services that are valued by our customers. In addition and in accordance with our commodity risk management policy, we generate income from limited trading activities. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including basis and gas daily contracts.

Our transportation and storage segment consists of natural gas gathering and intrastate transportation pipelines as well as three natural gas storage facilities with approximately 78 Bcf in storage capacity. The results from our transportation and storage segment are primarily derived from the fees we charge to transport natural gas on our pipelines, including a fuel retention component. We also generate 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 HPL System. Generally, HPL purchases its natural gas from either the market (including purchases from our midstream segment’s producer services) and from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers at the index price.

We also utilize our Bammel storage reservoir to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin.

As a result of our trading activities and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee, which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy. See further discussion regarding our risk management policies in Item 7A “Quantitative and Qualitative Disclosures about Market Risk” found elsewhere in this report.

 

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Retail and Wholesale Propane segments

Our propane-related segments are operated by HOLP, Titan and their respective subsidiaries engaged in the sale, distribution and marketing of propane and other related products through our retail and wholesale segments, (the propane segments). HOLP and Titan derive their revenue primarily from the retail propane segment. We believe that we are the third largest retail propane marketer in the United States, based on retail gallons sold. We serve more than 1,000,000 propane customers from 442 customer service locations in 41 states. Collectively, our propane-related segments accounted for approximately 13% of our consolidated operating income for the year ended August 31, 2006.

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 we have no control. Product supply contracts are generally 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. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. In particular, our propane business is largely seasonal and dependent upon weather conditions in our service areas.

Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income, 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 our first and second fiscal quarters; however, cash flow from operations is generally greatest during our 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.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information about normal temperatures to help us understand how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts related to our 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. The 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 MP Energy Partnership. MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest.

Summary of Operating Financial Performance in fiscal 2006

During the fiscal year ended August 31, 2006, we experienced record results in a volatile energy market caused by two hurricanes that hit the Texas and Louisiana coastlines and a warmer than normal winter. Prior to fiscal year 2006, we completed a number of acquisitions mainly in the midstream and transportation and storage operations and have been able to successfully integrate them into our existing pipeline systems. The integration and realized synergies allowed our pipeline systems to deliver strong financial results. We also added approximately 81,000 horsepower of compression during the year which allowed us to transport more natural gas on our pipelines.

 

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The industry also experienced higher commodity prices. NYMEX prices for the prompt month settlement averaged $8.95 during the year ended August 31, 2006 compared to an average price of $7.05 during fiscal year 2005. Higher natural gas prices tend to promote shippers to transport natural gas to more liquid markets. In addition, we experienced improved price differentials between the west and east Texas market hubs and better than expected processing margins towards the latter half of our fiscal year which allowed us to realize higher margins in our midstream and transportation and storage operations.

Despite the warmer than normal winter, our propane operations were able to deliver higher than expected results. Our retail volumes increased as a result of the Titan and other acquisitions during fiscal years 2006 and 2005 which offset the decrease in volumes we experienced due to the warmer weather. We also were able to increase our sales prices which improved our gross margins. Additionally, due to the acquisitions we made during fiscal years 2006 and 2005, our other propane segment revenues, such as appliance sales, labor and tank rentals, also improved over prior years.

Trends and Outlook

While there were certain anomalies that impacted our fiscal 2006 results, we believe our operations are again positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion plans that we expect to complete in fiscal year 2007, and our recently acquired Titan operations. We also expect to complete the acquisition of Transwestern Pipeline in the second quarter of fiscal year 2007, and upon closing, we expect the transaction to be immediately accretive to our Common Unitholders.

Natural gas prices have decreased since August 2006. To the extent natural gas prices remain low, our strategy to execute more fee-based contracts will allow us to continue to meet our cash obligations. Our ownership of the Bammel storage facility has also allowed us to hedge the purchase and sale of natural gas at favorable margin levels.

We also expect our propane-related segment to realize overall volume increases during fiscal year 2007 due to the effects of the Titan acquisition. However, continued warmer than normal weather will negatively impact volumes. We expect to be able to offset the impact of weather-related reduced volumes with reduced operating costs and improved gross margins to the extent our marketplace will allow it. We also plan to continue our active propane acquisition strategy and to expand our internal growth initiatives.

Recent Expansion Projects

42-inch project. On August 31, 2006 we announced the completion of the first phase of our previously announced 42-inch pipeline construction project. This segment, comprised of 97 miles of 42-inch natural gas pipeline, connects our 30-inch pipeline in Freestone County, the Bethel Storage Facility and our 30-inch Texoma pipeline in Rusk County. This portion of the 42-inch project has been placed in service and is currently flowing natural gas. The completion of this first phase provides us with additional take-away capacity to transport gas out of the Barnett Shale and Bossier Sands producing areas.

The full benefit of our 42-inch construction project will be recognized upon completion of the additional phases, all of which are currently underway and are on schedule to be completed by March 2007. Because of our increased transportation commitments, our Board of Directors approved a plan to upsize the recently announced 157-mile 36-inch expansion of this project to 42-inch for the section that runs from Limestone County, Texas to the interconnect with our Texoma pipeline, northeast of Beaumont. The increased upsizing will bring the estimated total cost of the project from $895.0 million to approximately $1.0 billion.

Transwestern Pipeline. On September 15, 2006, we announced the execution of agreements with GE Energy Financial Services and Southern Union Company to acquire the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. The agreements provide for a series of transactions in which we will acquire all of the member interests in CCE Holding, LLC (“CCEH”) owned by GE Energy Financial Services and certain other investors. The member interests acquired will represent a 50% ownership in CCEH, which was formed in 2004 to purchase CrossCountry Energy. In the second transaction, CCEH will redeem our 50% ownership of CCEH of the Partnership in exchange for 100% ownership of Transwestern, following which Southern Union will own all of the member interests of CCEH.

 

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The Transwestern Pipeline connects supply areas in the San Juan Basin in southern Colorado and northern New Mexico, the Anadarko Basin in the Mid-continent and the Permian Basin in west Texas to markets in the Midwest, Texas, Arizona, New Mexico and California. The Transwestern Pipeline interconnects with our existing intrastate pipelines in west Texas. The combination of pipeline systems will result in new market opportunities for existing natural gas supply sources on both systems and increases supply availability and flexibility to existing markets served by both systems. On November 1, 2006 we acquired the member interests in CCEH from GE and certain other investors for $1 billion and expect to complete the remaining series of transactions in the second quarter of fiscal year 2007. ETP financed the purchase price with its issuance of approximately 26.1 million ETP Class G Units issued to the Parent Company simultaneous with the closing.

Johnson County processing plant. The processing facility is being built in two phases to process rich natural gas produced from the Barnett Shale and will connect with our existing pipeline infrastructure. Phase I consists of a cryogenic gas plant with capacity of 115 MMcf/d, which is expected to be in service by the end of November 2006. Phase II of the project includes another 170 MMcf/d cryogenic gas plant and a 100 MMcf/d hydrocarbon dew point refrigeration plant, and is expected to be completed by the end of June 2007. The facility is being built to accommodate additional expansion in the future. The facility will be one of the few North Texas natural gas processing plants with access to two NGL pipeline outlets. The cost for this project is approximately $65.0 million.

36-inch pipeline expansion. The expansion is the result of our continued success in contracting transportation volumes. This 135-mile pipeline connects our existing Fort Worth Basin system to our 30-inch Texoma pipeline in Lamar County, Texas. The project expands producer’s options by providing additional market opportunities including the Carthage hub, interstate pipelines and industrial users along the Houston Ship Channel. It includes 27 miles of 30-inch pipe and 64,000 horsepower of compression with an initial capacity of 700 MMcf/d with expansion capabilities up to 1.0 Bcf/d. This expansion project will cost approximately $300.0 million.

Gathering Systems. We also acquired two small gathering systems in east and north Texas for an aggregate purchase price of $30.0 million. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25.0 million to be determined eighteen months from the closing date. These systems provide additional capacity in the Barnett Shale and in east Texas.

Analytical Analysis

The following is a discussion of our historical financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Form 10-K.

The Energy Transfer Transactions discussed previously 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 acquirer for accounting purposes. As a result, ETC OLP’s historical financial statements became our historical financial statements as the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to herein as Heritage.

The Energy Transfer Transactions affect the comparability of our financial statements for the year ended August 31, 2005 to the year ended August 31, 2004 because our consolidated financial statements for the year ended August 31, 2004 reflect the results of ETC OLP and its subsidiaries for the full period and the results of HOLP and HHI only from January 20, 2004 through August 31, 2004. The aggregate results in the propane segments disclosed below reflect Heritage’s historical results for the year ended August 31, 2004 combined with the historical results of Energy Transfer Company for the year ended August 31, 2004, and are 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 comparability of our financial statements is also affected by our purchase of Titan in June 2006, HPL in January 2005 and ET Fuel System in June 2004 and the sale of ETC Oklahoma (“Elk City”) in April 2005. See Note 2 to our consolidated financial statements for a detailed discussion of our significant acquisitions and dispositions during fiscal years 2006, 2005 and 2004.

Analysis of Operating Data

Volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation and storage, retail propane, and wholesale propane segments are as follows:

Midstream

 

     Years Ended August 31,
     2006    2005    2004

Natural gas sales, MMBtu/d

   1,552,753    1,578,833    1,026,773

NGL sales, Bbls/d

   10,425    12,707    6,920

 

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  For the year ended August 31, 2006, natural gas sales volumes decreased by 26,080 MMBtu/d compared to the year ended August 31, 2005. The decrease was principally due to less marketing activity by our producer services’ operations towards the latter half of fiscal year 2006 and a change in contract mix with one of our major producers where we now charge a fee to gather, process and transport natural gas rather than buying and selling the natural gas on our behalf. Our NGL sales volumes vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The decrease in NGL sales volumes is principally due to a change in contract mix as noted above and the election to by-pass our processing plant as a result of less favorable market conditions during the second fiscal quarter of the year ended August 31, 2006.

 

  For the year ended August 31, 2005, natural gas sales volumes were 1,578,833 MMBtu/d compared to 1,026,773 MMBtu/d for the year ended August 31, 2004, an increase of 552,060 MMBtu/d. The increase in natural gas sales volumes was a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004, as the Texas Chalk and Madison Systems essentially doubled the number of producing wells from 1,000 to 2,000. NGL sales volumes were 12,707 Bbls/d and 6,920 Bbls/d for the year ended August 31, 2005 and August 31, 2004, respectively. Our NGL sales volumes vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The increase in NGL sales volumes is principally due to the increased natural gas sales volumes processed through our processing plants.

Transportation and Storage

 

     Years Ended August 31,
     2006    2005    2004

Natural gas MMBtu/d – transported

   4,633,069    3,495,434    1,090,710

Natural gas MMBtu/d – sold

   1,580,638    1,361,729    —  

 

  For the year ended August 31, 2006, transported natural gas volumes increased by 1,137,635 MMBtu/d. The increase in transportation volumes is principally due to the increased volumes experienced in the Oasis Pipeline system, ET Fuel system and East Texas Pipeline system as a result of our effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Additionally, warmer weather during the 2006 fiscal year resulted in an increase in demand for natural gas. The higher temperatures required more demand for natural gas to be used by electricity-producing power plants connected to our assets. Natural gas sales volumes on the HPL System for the year ended August 31, 2006 increased 218,909 MMBtu/d compared to the year ended August 31, 2005, principally due to increased marketing efforts with our existing and new customers and increased well connects which has increased our supply on the HPL System.

 

  For the year ended August 31, 2005, transportation natural gas volumes increased by 2,404,724 MMBtu/d from 1,090,710 MMBtu/d to 3,495,434 MMBtu/d for the year ended August 31, 2005. The increase in transportation volumes is principally due to the increased volumes experienced on our 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 HPL System acquisition. As noted above, the transportation and storage segment also generates revenue and margin from the sale of natural gas on the HPL System to its customers. The HPL System’s natural gas sales volumes were 1,361,729 MMbtu/d for the period from acquisition to August 31, 2005 and it processed 1,735 Bbls/d during the same period.

Propane

 

     Years Ended August 31,
     2006    2005    2004    2004
                    (Aggregate)

Gallons sold

           

(in thousands)

           

Retail

   429,118    406,334    226,209    397,862

Wholesale

   79,348    70,047    35,719    64,399

 

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  Retail Propane. The 22.8 million net gallon increase in retail propane gallons sold for the year ended August 31, 2006, compared to the year ended August 31, 2005, includes a 24.5 million gallon increase due to the Titan acquisition for the months of June, July and August 2006, 15.9 million gallons were added through other propane acquisitions, offset by a decrease of 17.6 million gallons related to warm weather and higher propane commodity prices. The weather in our areas of operations during the year ended August 31, 2006 was 3.5% warmer than the year ended August 31, 2005 and 10.6% warmer than normal.

 

  For the year ended August 31, 2005 total retail propane gallons sold were 406.3 million gallons, compared to 226.2 million retail propane gallons reflected in the year ended August 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, we would have reflected an aggregate of 397.9 million retail gallons if the Energy Transfer Transactions would have occurred at the beginning of fiscal year 2004. The increase in fiscal year 2005 over fiscal year 2004 aggregate volumes is due to a 23.0 million gallon increase resulting from volumes sold by customer services locations added through acquisitions, offset by a 14.5 million gallon decline in volumes sold due in part to warmer weather. We experienced temperatures that were 6.9% warmer than normal and 0.7% warmer than the year ended August 31, 2004. We increased our marketing efforts to attain new customers, which partially offsets the negative factors described above.

 

  Wholesale Propane. For the year ended August 31, 2006, sales of wholesale propane gallons increased by 9.3 million gallons compared to the year ended August 31, 2005. Of this increase, 3.5 million is due to an increase in gallons sold in our U.S. wholesale operations as a result of several new customers in our eastern wholesale operations, and an increase of 5.8 million gallons in our Canadian wholesale operations related to increased marketing efforts in our Canadian operations.

 

  For the year ended August 31, 2005 we sold 70.0 million wholesale propane gallons as compared to 35.7 million gallons in the year ended August 31, 2004. As a comparison, we would have reflected aggregate volumes of 64.4 million gallons for the year ended August 31, 2004 if the Energy Transfer Transactions had occurred at the beginning of fiscal year 2004. Of the 5.6 million gallon increase in wholesale propane gallons in fiscal year 2005 over fiscal year 2004 aggregate volumes, 0.8 million is primarily due to customers added from an acquisition in December 2003, 5.4 million gallons is due to an increase in our foreign operations and we experienced a decrease of 0.6 million gallons related to warmer weather.

Analysis of Results of Operations

In the following analysis of results of operations, tabular dollar amounts are expressed in thousands.

Fiscal Year Ended August 31, 2006 Compared to Fiscal Year Ended August 31, 2005

Parent Company Only Results

The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and General Partner interests of ETP. The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

     Year Ended  
    

August 31,

2006

   

August 31,

2005

  

Amount of

Change

 

Equity in earnings of affiliates

   $ 204,987     $ 141,260    $ 63,727  

General and administrative expense

     55,374       1,051      54,323  

Interest expense

     36,773       9,529      27,244  

Loss on extinguishment of debt

     5,060       —        5,060  

Interest and other income (expense), net

     (638 )     16,066      (16,704 )

The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its Class A and Class B limited partner interests of ETP GP and its investment in ETP LLC. The change in equity in earnings of affiliates for the year ended August 31, 2006 compared to the year ended August 31, 2005 is directly related to the changes in the ETP segment income described below.

 

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General and Administrative Expenses. The increase in general and administrative expenses of the Parent Company for the year ended August 31, 2006 compared to the year ended August 31, 2005 is primarily due to the compensation expense of $52.9 million recorded in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO.

Interest Expense. The Parent Company interest expense increased for the year ended August 31, 2006 compared to 2005 because it had no significant debt prior to June 16, 2005 when it entered into a $600.0 million senior secured term loan agreement. In conjunction with its IPO, the Parent Company re-paid the $600.0 million senior secured term loan agreement and entered into a new revolving credit facility. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” below for more information on the Parent Company’s indebtedness.

Loss on Extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs in connection with the repayment of the $600.0 million senior secured term loan agreement as described above.

Interest and Other Income, net. In May 2005, the Parent Company exchanged 631,320 ETP Common Units held by the Parent Company and $1.0 million in cash for the redemption of 2,643,200 of its Limited Partner interests, which were then retired. A gain of $11.2 million was recorded in interest and other income, net in our consolidated statement of operations for the year ended August 31, 2005.

Consolidated Results

 

     Years Ended        
    

August 31,

2006

   

August 31,

2005

    Amount of
Change
 

Consolidated Information:

      

Revenues

   $ 7,859,096     $ 6,168,798     $ 1,690,298  

Cost of sales

     6,568,316       5,381,515       1,186,801  
                        

Gross margin

     1,290,780       787,283       503,497  

Operating expenses

     422,989       319,554       103,435  

Selling, general and administrative

     162,615       64,057       98,558  

Depreciation and amortization

     129,636       105,751       23,885  
                        

Consolidated operating income

     575,540       297,921       277,619  

Interest expense

     (150,646 )     (101,061 )     (49,585 )

Loss on extinguishment of debt

     (5,060 )     (6,550 )     1,490  

Equity in losses of affiliates

     (479 )     (376 )     (103 )

Gain (loss) on disposal of assets

     851       (330 )     1,181  

Interest and other income, net

     13,701       12,191       1,510  

Income tax expense

     (23,015 )     (4,397 )     (18,618 )

Minority interests

     (303,752 )     (96,946 )     (206,806 )
                        

Income from continuing operations

     107,140       100,452       6,688  

Income from discontinued operations, net of income tax and minority interest expense

     —         46,294       (46,294 )
                        

Net income

   $ 107,140     $ 146,746     $ (39,606 )
                        

See the detailed discussion of revenues, costs of sales, margin and operating expense by operating segment below.

Interest Expense. For the year ended August 31, 2006 compared to the year ended August 31, 2005, interest expense increased $49.6 million. The principal factor for this increase is a net $27.2 million increase in interest expense related to borrowings of the Parent Company, a net $22.1 million increase in interest expense related to borrowings on the 2005 Senior Notes and the Revolving Credit Facility which we entered into January 2005 to refinance debt at ETC OLP and fund the HPL acquisition, offset principally by an increase in unrealized gains of $1.2 million related to interest rate swaps. See Note 10 - “Price Risk Management Assets and Liabilities”, included in our consolidated financial statements for further discussion on interest rate hedges.

Loss on Extinguishment of Debt. The loss on extinguishment of debt during fiscal year 2006 is discussed above under “Parent Company Only Results.” During the year ended August 31, 2005, we refinanced certain debt and wrote off $6.6 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of $750.0 million of 5.95% senior notes. The write-offs were accounted for as loss on extinguishment of debt.

Interest and Other Income, Net. The increase in interest and other income for the year ended August 31, 2006 compared to the year ended August 31, 2005 is not material. Other income in fiscal year 2006 includes $7.7 million received from the favorable judgment on the SCANA litigation (see Notes 6 and 9 of our consolidated financial statements for further detail).

 

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Income Tax Expense. As a partnership, we are not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes. The increased expense of $18.6 million for the year ended August 31, 2006 is attributed principally to higher income due to gains on financial derivative activity recognized by a taxable subsidiary. No similar gains were realized by such subsidiary in prior periods.

Minority Interest Expense from Continuing Operations. The increase in minority interest expense is attributable to the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents partnership interests in ETP that we do not own.

Income from Continuing Operations. The increase in income from continuing operations of $6.7 million for the year ended August 31, 2006 compared to the year ended August 31, 2005, is principally due to acquisition-related income, increased volumes and margins on our midstream and transportation and storage assets and favorable price movement on our derivative positions during fiscal year 2006.

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 the year ended August 31, 2005, the income from discontinued operations included the gain on sale of the Elk City System of $142.5 million, net of income taxes, and revenues of $105.5 million offset by costs and expenses of $100.0 million and minority interest expense of $101.7 million, resulting in income from discontinued operations of $46.3 million.

There were no discontinued operations for the year ended August 31, 2006.

Net Income. Net income decreased by $39.6 million between the comparable years of August 31, 2006 and 2005. Excluding the $46.3 million of income from discontinued operations during the year ended August 31, 2005, net income increased by $6.7 million in fiscal year 2006, as compared to fiscal year 2005. The increase is principally due to the effect of the HPL acquisition described above, together with the effects of favorable price movements on financial derivative positions and increased volumes and margins on our midstream and transportation and storage assets.

Operating Results by Segment

Midstream Segment

 

     Years Ended     
    

August 31,

2006

  

August 31,

2005

   Amount of
Change

Revenues

   $ 4,223,544    $ 3,246,772    $ 976,772

Cost of sales

     4,000,461      3,102,539      897,922
                    

Gross Margin

     223,083      144,233      78,850

Operating expenses

     31,910      22,835      9,075

Selling, general and administrative

     23,922      9,685      14,237

Depreciation and amortization

     19,687      17,110      2,577
                    

Segment operating income

   $ 147,564    $ 94,603    $ 52,961
                    

Gross Margin. For the year ended August 31, 2006, midstream’s gross margin increased by $78.9 million. The increase was principally due to higher margins on gas sales made by our producer services and increased volumes on our gathering systems which resulted in higher fee-based revenues. Additionally, processing margins on our Southeast Texas System increased as a result of favorable processing conditions during the year ended August 31, 2006 compared to last year. The increase was offset by a decrease of $30.5 million in our trading activities principally due to a contingency accrual recorded during the three months ended August 31, 2006.

Operating Expenses. Midstream operating expenses increased $9.1 million and was primarily driven by $3.2 million in increased measurement expenses, $1.1 million in increased chemical costs, $0.7 million in scheduled compressor and pipeline maintenance expense and pipeline integrity costs, $0.9 million in employee costs, and increases of $3.2 million in other operating expenses.

 

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Selling, General and Administrative Expenses. The allocation of departmental costs between the midstream and the transportation and storage segments is based on factors such as headcount, number of meters, and on-going projects and is intended to fairly present the segment’s operating results. Midstream selling, general and administrative expenses for the year ended August 31, 2006 increased $14.2 million compared to the year ended August 31, 2005. The increase was attributable to increases of $28.5 million in employee-related costs such as salaries, incentive compensation and healthcare costs, insurance premium increases of $2.2 million, increases in office-related expenses of $4.0 million, $2.7 million in increased legal, audit and consulting fees, and increases in other general and administrative expenses of $2.0 million. The increase was offset by increases of $25.2 million in departmental costs allocated to the transportation and storage operating segment. The increased costs are principally due to the growth caused by the recent acquisitions, internal growth projects and upgraded information systems.

Depreciation and amortization. Midstream depreciation and amortization expense increased $2.6 million for the year ended August 31, 2006 compared to fiscal year 2005 is principally due to the Devon acquisition in November 2004 and pipeline and equipment placed into service subsequent to August 31, 2005.

Transportation and Storage Segment

 

     Years Ended     
    

August 31,

2006

   August 31,
2005
   Amount of
Change

Revenues

   $ 5,013,224    $ 2,608,108    $ 2,405,116

Cost of sales

     4,322,217      2,280,082      2,042,135
                    

Gross Margin

     691,007      328,026      362,981

Operating expenses

     171,312      113,166      58,146

Selling, general and administrative

     46,520      27,021      19,499

Depreciation and amortization

     50,755      36,020      14,735
                    

Segment operating income

   $ 422,420    $ 151,819    $ 270,601
                    

Gross Margin. For the year ended August 31, 2006 as compared to fiscal year 2005, transportation and storage gross margin increased by $363.0 million, principally due to the following:

 

  Increased volumes and prices. 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 our strategy to pursue additional volumes on our transportation pipeline systems. The price differential between the Waha and Katy market hubs increased between the 2005 and 2006 fiscal years, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable. We have also successfully secured more firm contracts as evidenced by our recent transportation agreement with XTO (see Note 10 to our consolidated financial statements). In addition, our Fort Worth Basin expansion, completed in May 2005, has also allowed shippers to move more gas from the Barnett Shale. Our margins for the year ended August 31, 2006 were also affected favorably by higher than normal temperatures during the year ended August 31, 2006 in regions where our assets are located. The higher temperatures increased demand for natural gas to be used by electricity-producing power plants connected to these assets. Furthermore, our margin was favorably impacted by an increase in fuel retention fees due to the increase in volumes on our transportation pipelines and an increase in average natural gas prices during the 2006 fiscal year compared to the 2005 fiscal year. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. We expect our gross margins to continue to increase as a result of this expansion and our recently announced expansion projects;

 

  The acquisition of HPL in January 2005. The results for the year ended August 31, 2005 contain seven months of HPL’s operating results as compared to twelve months of HPL’s operating results included in fiscal year 2006. For the year ended August 31, 2006, HPL’s margin was principally affected by the sale of natural gas held in storage during the winter months when demand for natural gas is strong, increased margins resulting from favorable pricing between the west and east markets in the Houston Ship Channel, and gains on derivatives as noted below. The favorable pricing was attributed to the effects of the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005. However, such margins were at lower levels than previously experienced during the three months ended November 30, 2005. Such pricing continues to remain at or below levels experienced during the three months ended November 30, 2005. Additionally, we sold approximately 16.0 Bcf of natural gas held in our Bammel storage facility during the three months ended August 31, 2006 compared to 10.6 Bcf during the three months ended August 31, 2005; and

 

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  Discontinued Hedge Accounting. In January and February 2006, we discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in our Bammel storage facilities. The discontinuation resulted from our determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable to occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during January 2006 through March 2006. As a result, during the year ended August 31, 2006, we recognized previously deferred unrealized gains of approximately $84.7 million from the discontinuation of hedge accounting.

Operating Expenses. Transportation and storage operating expenses increased $58.1 million when comparing the year ended August 31, 2006 to fiscal year 2005. The increase was principally attributable to increases of $32.4 million in operating expenses related to the HPL acquisition, $19.5 million related to compressor fuel consumption resulting from higher throughput volumes and increased gas prices during the year ended August 31, 2006, $2.1 million in property taxes, $2.5 million in pipeline maintenance, $1.4 million in compressor rental and maintenance, and $1.3 million in increased employee costs, offset by a decrease of $1.1 million in other operating expenses.

Selling, General and Administrative Expenses. Transportation and storage selling, general and administrative expenses increased $19.5 million for the year ended August 31, 2006 compared to the year ended August 31, 2005 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL acquisition and an increase in salaries and wages, incentive compensation expense, and other employee-related expenses.

Depreciation and amortization. Transportation and storage depreciation and amortization expense increased $14.7 million for the year ended August 31, 2006 compared to the year ended August 31, 2005. The increase was principally due to the HPL acquisition in January 2005, the Fort Worth Basin expansion project completed in May 2005 and additional compressors and equipment added to existing systems.

Retail Propane Segment

 

     Years Ended     
    

August 31,

2006

  

August 31,

2005

   Amount of
Change

Retail propane revenues

   $ 799,358    $ 641,071    $ 158,287

Other propane related revenues

     80,198      68,402      11,796

Retail propane cost of sales

     493,642      384,186      109,456

Other propane related cost of sales

     21,776      19,554      2,222
                    

Gross margin

     364,138      305,733      58,405

Operating expenses

     212,188      176,277      35,911

Selling, general and administrative

     17,859      11,067      6,792

Depreciation and amortization

     58,036      51,487      6,549
                    

Segment operating income

   $ 76,055    $ 66,902    $ 9,153
                    

Revenues. Of the total increase in retail propane revenue of $158.3 million between the years ended August 31, 2006 and 2005, $47.1 million is due to the increase in volumes sold by customer service locations added through the Titan acquisition in June 2006, $29.6 million is due to the increase in volumes sold by customer service locations added through other propane acquisitions and $114.4 million is due to higher selling prices. These increases were offset by a decrease of $32.8 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $11.8 million for the year ended August 31, 2006 compared to fiscal year 2005 primarily due to other propane related revenues of companies we have acquired between the two years.

Costs of Sales. During the year ended August 31, 2006 compared to the year ended August 31, 2005, retail propane cost of sales increased by $109.5 million of which $30.8 million is a result of an overall increase in gallons sold by customer service locations added through the Titan acquisition, $18.2 million due to an overall increase in gallons sold by customer service locations added through other propane acquisitions and $80.7 million is due to higher cost of fuel, offset by a decrease of $20.2 million due to the impact of weather related volumes described above.

Gross Margin. The overall increase in gross margins for the year ended August 31, 2006 compared to fiscal year 2005 is a function of acquisition-related increases and higher sales prices.

 

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Operating Expenses. During the year ended August 31, 2006, operating expenses increased by $35.9 million compared to last year due to a combination of a $21.4 million increase due to the Titan acquisition, a $9.2 million increase in our employee base from other acquisitions and annual salary increases, $3.4 million due to higher fuel costs to run our vehicles and other vehicle expenses, and a $4.7 million general increase in other operating expenses primarily from other acquisitions, offset by a $2.8 million net decrease in other operating expenses.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the comparable years of August 31, 2006 and 2005 is primarily due to increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding.

Depreciation and Amortization. The increase in depreciation and amortization of $6.5 million is primarily due to the depreciation and amortization of assets added through acquisitions.

Operating Income. For the year ended August 31, 2006, total operating income increased by $9.2 million compared to the year ended August 31, 2005. This increase is primarily due to the changes in revenues and expenses described above.

Wholesale Propane Segment

 

     Years Ended        
    

August 31,

2006

  

August 31,

2005

    Amount of
Change
 

Revenues

   $ 94,288    $ 68,833     $ 25,455  

Cost of sales

     87,337      64,667       22,670  
                       

Gross margin

     6,951      4,166       2,785  

Operating expenses

     3,031      3,139       (108 )

Selling, general and administrative

     1,916      1,564       352  

Depreciation and amortization

     742      754       (12 )
                       

Segment operating income (loss)

   $ 1,262    $ (1,291 )   $ 2,553  
                       

Revenues. Of the increase of $25.5 million in wholesale revenue for the year ended August 31, 2006 compared to fiscal year 2005, $11.3 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale and Canadian operations and $14.2 million is related to higher selling prices.

Costs of Sales. For the year ended August 31, 2006 compared to fiscal year 2005, total cost of sales increased by $22.7 million. Of the increase, $12.4 million is due to higher selling prices and $10.3 million is due to the increase in customers in our eastern wholesale operations described above.

Gross Margin. The overall increase in gross margin for the year ended August 31, 2006 compared to August 31, 2005, is primarily a function of the activities described above in revenues and costs related to the new customers in our eastern wholesale and Canadian operations.

Operating Income (Loss). The increase in operating income of $2.6 million during the year ended August 31, 2006, compared to fiscal year 2005 is primarily due to the changes in revenues and expenses described above.

Other

 

     Years Ended     
    

August 31,

2006

  

August 31,

2005

   Amount of
Change

Revenue

   $ 7,740    $ 6,867    $ 873

Cost of sales

     2,139      1,742      397

Operating expenses

     4,548      4,137      411

Depreciation and amortization

     416      380      36
                    

Other operating income

   $ 637    $ 608    $ 29
                    

Unallocated selling, general and administrative expenses

   $ 72,398    $ 14,720    $ 57,678
                    

Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that relate to the general operations of the Partnership are not allocated to our segments.

Unallocated selling, general and administrative expenses increased $57.7 million for the year ended August 31, 2006 compared to the year ended August 31, 2005. This increase is primarily attributed to compensation expense of $52.9

 

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million recorded in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO, a $1.0 million increase in executive salaries due to additional staffing, a $0.4 million increase in professional fees due to our on-going efforts related to the Sarbanes-Oxley Act and other Partnership expenses, and a $2.5 million increase in additional executive bonuses and non-cash compensation related to additional staffing and outstanding restricted units awards.

Fiscal Year Ended August 31, 2005 Compared to Fiscal Year Ended August 31, 2004

Parent Company Only Results

 

     Year Ended  
    

August 31,

2005

  

August 31,

2004

   Amount of
Change
 

Equity in earnings of affiliates

   $ 141,260    $ 55,602    $ 85,658  

Interest expense

     9,529      —        9,529  

Gain on Energy Transfer Transactions

     —        395,253      (395,253 )

Interest and other income, net

     16,066      167      15,899  

The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its direct and indirect investment in limited and general partner interests of ETP. The change in equity in earnings of affiliates for the year ended August 31, 2006 compared to the year ended August 31, 2005 is directly related to the changes in the ETP segment income described below.

Interest Expense. The Parent Company interest expense increased for the year ended August 31, 2005 compared to 2004 because it had no significant debt prior to June 16, 2005 when it entered into a $600.0 million senior secured term loan agreement.

Gain on Energy Transfer Transactions. In accordance with EITF 90-13 and SFAS 141, the Parent Company recorded a gain of $395.3 million during the year ended August 31, 2004 as a result of the Energy Transfer Transactions. The total gain recorded was increased to the extent that distributions received by the Parent Company from ETC OLP in the transactions exceeded the investment in ETC OLP prior to the transactions.

Interest and Other Income, net. In May 2005, the Parent Company exchanged 631,320 ETP Common Units held by the Parent Company and $1.0 million in cash for the redemption of 2,643,200 of its Limited Partner interests, which were then retired. A gain of $11.2 million was recorded in interest and other income, net in our consolidated statement of operations for the year ended August 31, 2005.

Consolidated Results

 

     Year Ended  
    

August 31,

2005

   

August 31,

2004

 

Revenues

   $ 6,168,798     $ 2,346,957  

Cost of sales

     5,381,515       1,981,424  
                

Gross margin

     787,283       365,533  

Operating expenses

     319,554       147,374  

Selling, general and administrative

     64,057       31,111  

Depreciation and amortization

     105,751       56,242  
                

Consolidated operating income

     297,921       130,806  

Interest expense

     (101,061 )     (41,217 )

Loss on extinguishment of debt

     (6,550 )     —    

Equity in earnings (losses) of affiliates

     (376 )     363  

Loss on disposal of assets

     (330 )     (1,006 )

Gain on Energy Transfer Transactions

     —         395,253  

Interest and other income, net

     12,191       516  

Income tax expense

     (4,397 )     (2,792 )

Minority interests

     (96,946 )     (35,164 )
                

Income from continuing operations

     100,452       446,759  

Income from discontinued operations, net of income tax expense

     46,294       3,458  
                

Net income

   $ 146,746     $ 450,217  
                

 

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Interest Expense. Interest expense was $101.1 million for the year ended August 31, 2005 as compared to $41.2 million for the year ended August 31, 2004. Of the $59.9 million increase for the year ended August 31, 2005 as compared to the year ended August 31, 2004, $12.7 million is due to the interest of our propane segments for a full year in fiscal year 2005 whereas for the year ended August 31, 2004, prior to the Energy Transfer Transactions propane segment interest expense was not included in expense. $8.1 million is primarily the result of our existing $600 million term loan agreement and other borrowing of ETE. $43.5 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility in January 2005 to finance the HPL acquisition, $1.0 million is related to the amortization of financing costs and the bond discount related to the Senior Notes and the Revolving Credit Facility, offset by a decrease of $1.5 million from gains on interest rate swaps that was included in interest expense during the year ended August 31, 2005 and was not present in 2004, $2.0 million that is attributed to reduced interest in our midstream and transportation and storage segments due to the reduction of long term debt in January 2005 and the effects of interest rate swaps accounted for at ETC OLP, and a $1.9 million decrease in interest expense in our propane segments which is primarily due to the reduction of principal on several of HOLP’s Senior Secured Notes from annual payments during the year ended August 31, 2005.

Loss on Extinguishment of Debt. As a result of refinancing certain debt during the year ended August 31, 2005, ETP wrote off $6.6 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of $750.0 million of 2015 unregistered Senior Notes. The write-off was accounted for as a loss on extinguishment of debt.

Income Tax Expense. Income tax expense was $4.4 million for the year ended August 31, 2005 as compared to $2.8 million for the year ended August 31, 2004. The increase in income tax expense is due to (1) income tax expense recorded in HHI for the entire period in the year ended August 31, 2005 as compared with the year ended August 31, 2004, when tax expense related to HHI was only included in our 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 tax-paying subsidiary.

Income from Continuing Operations. Income from continuing operations for the year ended August 31, 2005 was $100.5 million as compared to income from continuing operations of $446.8 million for the year ended August 31, 2004. The decrease from the 2004 year end to 2005 year end is principally due to the gain on the Energy Transfer Transactions that was recorded in the year ended August 31, 2004. The decrease was partially offset by acquisition-related income during the fiscal year ended August 31, 2005.

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 period from September 1, 2004 to April 14, 2005 as compared to $135.3 million for the year ended August 31, 2004. Costs and expenses of the Elk City System were $100.0 million for the period from September 1, 2004 to April 14, 2005 and $129.1 million for the year ended August 31, 2004. Income from discontinued operations for the period from September 1, 2004 to April 14, 2005 and for the year ended August 31, 2004 was $5.5 million and $6.2 million, respectively. The decrease in revenues, expenses and income was principally due to the sale occurring in April 2005. The gain on the sale of the Elk City System was $106.1 million, net of related income tax expense of $1.8 million.

Minority interest expense from discontinued operations. Minority interest expense from discontinued operations was $65.3 million for the year ended August 31, 2005 compared to $2.7 million for the year ended August 31, 2004. The increase of $62.6 million was primarily related to the gain on the sale of discontinued operations.

 

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Operating Results by Segment

Midstream Segment

 

     Years Ended
    

August 31,

2005

  

August 31,

2004

Revenues

   $ 3,246,772    $ 1,880,663

Cost of sales

     3,102,539      1,787,849
             

Gross Margin

     144,233      92,814

Operating expenses

     22,835      12,540

Selling, general and administrative

     9,685      10,222

Depreciation and amortization

     17,110      12,451
             

Segment operating income

   $ 94,603    $ 57,601
             

Gross Margin. Midstream’s gross margin increased $51.4 million from $92.8 million for the year ended August 31, 2004 to $144.2 million for the year ended August 31, 2005. The increase is principally due to increases in margin pertaining to increased volumes experienced on our Southeast Texas System and increased marketing efforts by our producer services. In addition, fee-based revenue increased principally due to increased processing, treating and gathering fees resulting from the increased throughput volumes and the acquisition of the Texas Chalk and Madison System in November 2004. The increase in fee based revenue was also due to a change in the contract mix with a major producer during the third quarter of our 2005 fiscal year; however, this change should have no effect on overall midstream margins. The increase in margin during the year ended August 31, 2005 was also due to mark-to-market gains resulting from favorable price movements in relation to our overall derivative positions. The price movements were a result of the effects of Hurricane Katrina during the latter part of August 2005.

Operating Expenses. For the year ended August 31, 2005, Midstream operating expenses increased $10.3 million to $22.8 million from $12.5 million for the year ended August 31, 2004. The increase was principally due to $3.1 million in increased compressor and pipeline maintenance, $1.8 million in increased measurement expenses, $1.8 million in increased property taxes, and $3.6 million, in the aggregate, of other operating expenses such as chemicals, electricity, and other plant operating expenses, primarily due to the Texas Chalk and Madison Systems’ acquisition and increased throughput experienced on our existing systems.

Selling, General and Administrative Expenses. Midstream selling, general and administrative expenses decreased from $10.2 million for the year ended August 31, 2004 to $9.7 million for the year ended August 31, 2005. The decrease was principally due to $9.5 million in certain departmental costs incurred by the midstream segment and allocated to the transportation and storage operating segment. The decrease was offset by increases of $6.7 million in employee-related expenses such as salary, incentive compensation and health care costs, and $2.1 million in other general and administrative costs such as office, legal, and insurance expense.

Depreciation and Amortization. Midstream depreciation and amortization was $17.1 million for the year ended August 31, 2005 compared to $12.5 million for the year ended August 31, 2004, an increase of $4.6 million. The increase was principally due to the Texas Chalk and Madison Systems’ acquisition in November 2004.

Transportation and Storage Segment

 

     Years Ended
    

August 31,

2005

  

August 31,

2004

Revenues

   $ 2,608,108    $ 113,938

Cost of sales

     2,280,082      11,270
             

Gross Margin

     328,026      102,668

Operating expenses

     113,166      30,571

Selling, general and administrative

     27,021      8,372

Depreciation and amortization

     36,020      12,255
             

Segment operating income

   $ 151,819    $ 51,470
             

Gross Margin. Transportation and storage gross margin was $328.0 million for the year ended August 31, 2005 as compared to $102.7 million for the year ended August 31, 2004, an increase of $225.3 million. The increase in transportation and storage gross margin is principally due to the following:

 

  Increased volumes on our 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 our strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. Additionally, the average differential between the Waha market hub and Katy market hub increased $0.051 from $0.249 for the year ended August 31, 2004 to $0.30 for the year ended August 31, 2005, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable.

 

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  ET Fuel System acquisition in June 2004. In connection with the acquisition of the ET Fuel System in June of 2004, we entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115.6 billion Btu per year. We 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. During the third fiscal quarter of 2005, we were 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. As a result, we recognized an additional $14.7 million in fees during the third fiscal quarter of 2005. The increase in margin was also due to the Fort Worth Basin expansion completed in May 2005.

 

  East Texas System. We completed the East Texas System in June 2004.

 

  HPL System acquired in January 2005. As discussed above, we expect significant fluctuations in our margins from period to period on the HPL System due to the timing of injections and withdrawals of working natural gas.

Operating Expenses. For the year ended August 31, 2005, transportation and storage operating expenses were $113.2 million as compared to $30.6 million for the year ended August 31, 2004, an increase of $82.6 million. The increase was principally attributable to the ET Fuel System acquisition in June 2004, the completion of the East Texas Pipeline in June 2004 and the acquisition of HPL in January 2005. In addition, Oasis Pipeline’s operating expenses increased $9.1 million as a result of increased gas consumption required to transport natural gas through the pipeline and increases in other operating expenses such as compressor and pipeline maintenance and ad valorem taxes.

Selling, General and Administrative Expenses. Transportation and storage selling, general and administrative expenses increased $18.6 million to $27.0 million for the year ended August 31, 2005 from $8.4 million for the year ended August 31, 2004. The increase was principally due to $9.0 million in general and administrative expenses related to the HPL acquisition, $1.4 million in general and administrative expenses relating to the ET Fuel acquisition, and $9.5 million related to certain department costs allocated from the midstream segment.

Depreciation and Amortization. For the year ended August 31, 2005 transportation and storage depreciation and amortization increased $23.7 million from $12.3 million for the year ended August 31, 2004 to $36.0 million for the year ended August 31, 2005. The increase was principally attributable to the acquisitions of the ET Fuel System and HPL System during the 2005 fiscal period and the completion of the East Texas Pipeline in June 2004.

Retail Propane Segment

 

    

Years Ended

     August 31,
2005
   August 31,
2004
   August 31,
2004
     (Actual)    (Actual)    (Aggregate)

Retail propane revenues

   $ 641,071    $ 315,177    $ 536,636

Other propane related revenues

     68,402      34,167      60,646

Retail propane cost of sales

     384,186      174,769      296,206

Other propane related cost of sales

     19,554      9,602      17,512

Operating expenses

     176,277      100,093      158,471

Selling, general and administrative

     11,067      6,746      11,080

Depreciation and amortization

     51,487      30,925      45,979
                    

Segment operating income

   $ 66,902    $ 27,209    $ 68,034
                    

Revenues. For the year ended August 31, 2005, we had retail propane revenues of $641.1 million as compared to retail propane revenues of $315.2 million for the year ended August 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 year ended August 31, 2004, aggregate retail propane revenues would have been $536.6 million. Of the $104.5 million aggregate increase, $36.3 million is due to the increase in volumes sold by customer service locations added through acquisitions, $91.1 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; offset by a decrease of $22.9 million due to the adverse impact weather had on volumes, as described above. We had other propane related revenues of $68.4 million for the year ended August 31, 2005 compared to $34.2 for the year ended August 31, 2004. As a comparison, aggregate other propane related revenues would have been $60.6 million for the year ended August 31,

 

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2004. The aggregate increase of $7.8 million for the year ended August 31, 2005 compared to the year ended August 31, 2004 is primarily due to other propane revenue from companies acquired during the year ended August 31, 2005 and higher cost of propane related resale items which we have recovered through an increase of our selling prices.

Costs of Sales. For the year ended August 31, 2005, we had retail propane cost of sales of $384.2 million compared to retail propane cost of sales of $174.8 million for the year ended August 31, 2004. As a comparison, for the year ended August 31, 2004, aggregate retail propane cost of sales would have been $296.2 million. Of the $88.0 million aggregate increase for the year ended August 31, 2005 as compared to the year ended August 31, 2004, $80.0 million reflects the increase due to higher cost of fuel, and $8.0 million is due to the increase in volumes described above. We had other propane related cost of sales of $19.5 million for the year ended August 31, 2005 as compared to $9.6 million for the year ended August 31, 2004. As a comparison, we had aggregate other propane related cost of sales of $17.5 million. The aggregate increase for the year ended August 31, 2005 as compared to the year ended August 31, 2004 is primarily due to acquisition related cost of sales for the year ended August 31, 2005 and higher cost of resale items.

Operating Expenses. For the year ended August 31, 2005, operating expenses for the retail propane segment were $176.3 million and $100.1 million for the year ended August 31, 2004. As a comparison, aggregate retail propane operating expenses would have been $158.5 million for the year ended August 31, 2004, or an aggregate increase of $17.8 million. Of this aggregate increase, approximately $8.7 million related to an increase in our employee base from acquisitions, $3.1 million is due to higher fuel costs to run our vehicles and other vehicle expenses, net business insurance increased $3.1 million, and a remaining increase of $2.9 million due to a general increase in other operating expenses from acquisitions.

Selling, General and Administrative Expenses. For the year ended August 31, 2005, selling, general and administrative expenses for our retail propane segment were essentially equal to aggregate retail propane selling, general and administrative expenses of $11.1 million for the year ended August 31, 2004.

Depreciation and Amortization. For the year ended August 31, 2005, depreciation and amortization in our retail propane segment was $51.5 million as compared $30.9 million for the year ended August 31, 2004. We would have had aggregate depreciation and amortization of $46.0 million for the year ended August 31, 2004. The aggregate increase of $5.5 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 year ended August 31, 2005, we had retail propane operating income of $66.9 million as compared to retail propane operating income of $27.2 million for the year ended August 31, 2004. Aggregate total operating income for the year ended August 31, 2004 was $68.0 million. These variances are primarily due to changes in revenues and expenses described above.

Wholesale Propane Segment

 

     Years Ended  
     August 31,
2005
    August 31,
2004
    August 31,
2004
 
     (Actual)     (Actual)     (Aggregate)  

Revenues

   $ 68,833     $ 27,345     $ 47,941  

Cost of sales

     64,667       24,871       43,410  

Operating expenses

     3,139       1,936       2,912  

Selling, general and administrative

     1,564       918       1,443  

Depreciation and amortization

     754       432       626  
                        

Segment operating loss

   $ (1,291 )   $ (812 )   $ (450 )
                        

Revenues. For the year ended August 31, 2005, wholesale propane revenues were $68.8 million, compared to $27.3 million for the year ended August 31, 2004. Aggregate wholesale propane revenues were $47.9 million for the year ended August 31, 2004. Of the aggregate increase of $20.9 million, $0.9 million is due to the increase in gallons due to acquisitions, $15.5 million is related to higher selling prices, and $5.1 million is due to increased marketing efforts in our foreign operations, offset by the decrease of $0.6 million due to weather related gallons described above.

Costs of Sales. For the year ended August 31, 2005, wholesale propane cost of sales was $64.7 million and $24.9 million for the year ended August 31, 2004. As a comparison, aggregate wholesale propane cost of sales would have

 

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been $43.4 million for the year ended August 31, 2004. The aggregate increase of $21.3 million is due to a $17.1 million increase from higher selling prices, and a $4.8 increase due to the increase in volumes in our foreign market described above, offset by a $0.6 million decrease due to weather related volumes described above.

Operating Expenses. For the year ended August 31, 2005, operating expenses for our wholesale propane segment were $3.1 million and $1.9 million for the year ended August 31, 2004, and aggregate wholesale propane operating expenses of $2.9 million for the year ended August 31, 2004, or no significant variance.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our wholesale propane segment were $1.6 million for the year ended August 31, 2005, compared to wholesale selling, general, and administrative expenses of $0.9 for the year ended August 31, 2004. As a comparison, we had aggregate wholesale selling, general, and administrative expenses of $1.4 million for the year ended August 31, 2004, or no significant variation.

Operating Loss. For the year ended August 31, 2005, we had a domestic wholesale propane operating loss of $1.3 million as compared to operating loss of $0.8 million for the year ended August 31, 2004. Aggregate total operating loss for the year ended August 31, 2004 would have been $0.4 million. The variances are due to the factors described above.

Other

 

     Years Ended
    

August 31,

2005

  

August 31,

2004

  

August 31,

2004

     (Actual)    (Actual)    (Aggregate)

Revenue

   $ 6,867    $ 3,465    $ 5,283

Cost of sales

     1,742      861      1,304

Operating expenses

     4,137      2,234      3,614

Depreciation and amortization

     380      179      321
                    

Other operating income

   $ 608    $ 191    $ 44
                    

Unallocated selling, general and administrative expenses

   $ 14,720    $ 4,853    $ 10,095
                    

Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that relate to the general operations of the Partnership are not allocated to our segments.

For the year ended August 31, 2005, the total unallocated selling, general, and administrative expenses were $14.7 million as compared to $4.9 million unallocated selling, general, and administrative expense for the year ended August 31, 2004. Aggregate total unallocated selling, general, and administrative expense for the year ended August 31, 2004 would have been $10.1 million. The aggregate increase of $4.6 million in unallocated selling, general, and administrative expenses is primarily related to the $4.4 million expense related to our ongoing efforts to comply with the Sarbanes Oxley Act and additional executive wages charged to unallocated selling, general and administrative expenses during fiscal year 2005, offset by approximately $4.5 million of transaction costs related to the Energy Transfer Transactions.

Income Taxes

As a Partnership we generally are not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended August 31, 2006, 2005 and 2004, our non-qualifying income was not expected to, or did not, exceed the statutory limit.

The difference between the statutory rate and the effective rate is summarized as follows:

 

     Year Ended August 31,  
     2006     2005     2004  

Federal statutory tax rate

   35.00 %   35.00 %   35.00 %

State income tax rate net of federal benefit

   3.10 %   3.56 %   3.96 %

Earnings not subject to tax at the Partnership level

   (32.80 )%   (36.58 )%   (38.39 )%
                  

Effective tax rate

   5.30 %   1.98 %   0.57 %
                  

 

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Income tax expense consists of the following current and deferred amounts:

 

     Year Ended August 31,  
     2006     2005     2004  

Current income tax expense:

      

Federal

   $ 27,640     $ 5,042     $ 6,505  

State

     1,987       963       830  

Deferred income tax expense (benefit):

      

Federal

     (6,227 )     (2,015 )     (4,366 )

State

     (385 )     407       (177 )
                        

Total income tax expense before gain on discontinued operations

     23,015       4,397       2,792  

Gain on discontinued operations:

      

Current income tax expense:

      

Federal

     —         1,570       —    

State

     —         259       —    
                        
     —         1,829       —    
                        

Total income tax expense

   $ 23,015     $ 6,226     $ 2,792  
                        

We do not expect our tax payments in any year to differ significantly from our current tax provisions.

On May 18, 2006, the Governor of Texas signed into law House Bill 3 (HB-3) which modifies the existing franchise tax law. The modified franchise tax will be computed by subtracting either costs of goods sold or compensation expense, as defined in HB-3, from gross revenue to arrive at a gross margin. The resulting gross margin will be taxed at a one percent tax rate. HB-3 has also expanded the definition of tax paying entities to include limited partnerships such as ours. HB-3 becomes effective for activities occurring on or after January 1, 2007. Based on our initial analysis, we do not believe HB-3 will have a significant adverse impact on our financial position or operating cash flows.

Liquidity and Capital Resources

Parent Company Only

The Parent Company currently has no separate operating activities apart from those conducted by the Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and General Partner interests of ETP. The amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP.

In February 2006, the Parent Company completed its IPO of 24,150,000 Common Units at a price of $21.00 per unit. Proceeds from the IPO were $478.9 million, net of underwriter’s discount. The Parent Company paid equity issue costs of $4.1 million related to the units issued, and paid $131.6 million to its former owners for the redemption of a portion of their previously outstanding Common Units.

On July 17, 2006, the Parent Company purchased 9,642,757 of its Common Units from one of the Common Unitholders for an aggregate purchase price of approximately $237,817. The purchase was funded with a combination of borrowings from the Parent Company’s $500.0 million Revolving Credit Facility and a new $150.0 million Senior Secured Term Loan Facility which is discussed under “Description of Indebtedness” below.

On November 1, 2006, ETP issued approximately 26.1 million of its Class G Units to the Parent Company for $1.2 billion, at a price of $46.00 per unit based upon a market discount from the closing price of ETP’s Common Units on October 31, 2006. The ETP Class G Units were issued to the Parent Company pursuant to a customary agreement, and the Parent Company has been granted registration rights. ETP used the proceeds of $1.2 billion in order to fund a portion of the Transwestern Pipeline acquisition and to repay indebtedness ETP incurred in connection with the Titan acquisition as discussed above. The terms of the Class G Units are substantially similar to those of ETP’s previous Class F Units, as discussed in Note 7 to our consolidated financial statements.

 

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On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.

In a separate but related transaction, ETE acquired from ETI, the remaining 50% general partner Incentive Distributions Rights (“IDRs”) of ETP, which resulted in ETE now owning 100% of the IDRs. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units for all ETI interests.

ETP

ETP’s ability to satisfy its obligations and pay distributions to its partners will depend on 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.

ETP’s future capital requirements will generally consist of:

 

  maintenance capital expenditures, which include capital expenditures made to connect additional wells to its natural gas systems in order to maintain or increase throughput on existing assets for which it expects to expend $38.3 million in the next fiscal year 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 for which ETP expects to expend $22.7 million in the next fiscal year;

 

  growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which it expect to expend $988.6 million in the next fiscal year; and customer propane tanks for which it expects to expend $25.5 million in the next fiscal year; and

 

  acquisition capital expenditures including acquisition of new pipeline systems and propane operations.

ETP believes that cash generated from the operations of its businesses will be sufficient to meet anticipated maintenance capital expenditures. ETP will initially finance all capital requirements by cash flows from operating activities. To the extent that its 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;

 

  growth capital expenditures will be financed by the proceeds of borrowings under the existing ETP credit facilities and the issuance of additional Common Units or a combination thereof; and

 

  acquisition capital expenditures will be financed by the proceeds of borrowings under the existing ETP credit facilities, other ETP lines of credit, long-term debt, the issuance of additional Common Units 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 and storage segments, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than those expenditures necessary to maintain the service capacity of ETP’s existing assets.

In connection with the HPL acquisition, ETP 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.

On October 3, 2006, ETP announced that it entered into a long-term agreement with CenterPoint Energy Resources Corp (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on its HPL System located along the Texas gulf coast region. Under the terms of this agreement, CenterPoint has contracted for

 

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129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in ETP’s Bammel Storage facility. Under the new agreement with CenterPoint, ETP will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This will reduce ETP’s working capital requirements that were necessary to finance the working gas while in storage and will provide ETP an opportunity to offer storage to third parties. This agreement goes into effect beginning April 1, 2007.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our 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 our acquisitions, including the recently acquired Titan operations, and other factors.

Operating Activities. Cash provided by operating activities during year ended August 31, 2006, was $310.8 million as compared to cash provided by operating activities of $38.1 million for the year ended August 31, 2005. The net cash provided by operations for the year ended August 31, 2006 consisted of net income of $107.1 million, non-cash charges of $304.1 million, principally minority interests, unit-based compensation, depreciation and amortization and deferred taxes, and operating funds used of $100.4 million which decreased components of working capital. 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, and the timing of the purchase and sale of inventories related to the propane and transportation and storage operations. Accounts receivable and accounts payable both decreased during the year ended August 31, 2006 due primarily to decreases in the volumes and prices in the midstream segment. Customer deposits decreased significantly during the year ended August 31, 2006 due to the delivery of natural gas in 2006 that was prepaid as of August 2005. Accrued liabilities increased significantly during the year ended August 31, 2006, due to certain provisions for environmental, legal and other contingencies.

Investing Activities. Cash used in investing activities during the year ended August 31, 2006 of $1.2 billion is comprised primarily of cash paid for acquisitions of $586.2 million, $680.2 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations and $4.6 million for advances and investments in affiliates. Cash used in investing activities was offset by proceeds from the sale of idle property of $6.9 million and cash received for a working capital settlement on the HPL acquisition of $19.6 million. The cash paid for acquisitions included primarily $16.6 million paid for the acquisition of the 2% remaining interests in the HPL System, cash paid for the Titan acquisition of $548.5 million, and other retail propane acquisitions of $20.6 million. In addition to cash paid for acquisitions, we also issued $4.0 million of Common Units in connection with a specific propane acquisition.

Financing Activities. Cash provided by financing activities during the year ended August 31, 2006 was $926.4 million primarily due to the net increase of $928.8 million in debt financing which we used to fund capital expenditures and to fund the repurchase of $237.8 million of the Parent Company’s Common Units from a former Unitholder. We also had a payment of $131.6 million to the former owners of the Parent Company for the redemption of a portion of their previously outstanding Common Units which was funded with a portion of the $474.0 million proceeds from the Parent Company IPO, net of underwriter’s discounts and issue costs. We paid $101.3 million in distributions to our Common Unitholders during the year ended August 31, 2006. We also paid other financing costs of $5.7 million during the year ended August 31, 2006.

Financing and Sources of Liquidity

Description of Indebtedness

Our indebtedness as of August 31, 2006 consists of the Parent Company’s Senior Secured Credit Agreement which includes a $500.0 million Senior Secured Revolving Credit Facility available through February 8, 2011, and a $150.0 million Senior Secured Term Loan Facility due February 8, 2012. ETP has $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, a Revolving Credit Facility that allows for borrowings of up to $1.3 billion, expanded to $1.5 billion subsequent to August 31, 2006, available through June 29, 2011, and a $200.0 million Revolving Credit Facility that matures on December 1, 2006 (paid and canceled subsequent to August 31, 2006). We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our subsidiaries are described in more detail below and in

 

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Note 6 to our consolidated financial statements included under item 8 of this Form 10-K. Failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and our and our subsidiaries’ ability to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of August 31, 2006, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.

Parent Company Indebtedness

Senior Secured Credit Agreement

Simultaneous with our IPO, the Parent Company entered into a Senior Secured Credit Agreement (the “Parent Company Senior Secured Credit Agreement”) with Wachovia Bank, National Association, as Administrative Agent for a group of banks. The Parent Company Senior Secured Credit Agreement includes a $500.0 million Senior Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility replaced the 2005 Senior Secured Term Loan Agreement described below. The Parent Company Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $10.0 million and a daily rate based on LIBOR. On July 3, 2006, the Parent Company amended its Senior Secured Credit Agreement to provide for a $150.0 million Senior Secured Term Loan Facility due February 8, 2012, all of which was outstanding at August 31, 2006 (the “Senior Secured Term Loan Facility”).

The outstanding amount borrowed under the Parent Company Revolving Credit Facility as of August 31, 2006 was $466.3 million which includes $0.7 million under the Swingline loan option. The total amount available under the Parent Company Revolving Credit Facility as of August 31, 2006 was $33.7 million. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to bank syndication’s approval, to expand the facilities capacity for up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility and the Senior Secured Term Loan Facility bear interest at the Parent Company’s 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 the Parent Company’s leverage ratio. The weighted average interest rate was 6.76% for the amount outstanding on the Parent Company Revolving Credit Facility and 7.5% on the Senior Secured Term Loan Facility as of August 31, 2006.

The Parent Company Senior Secured Credit Agreement and Senior Secured Term Loan Facility are secured by a lien on the Parent Company’s assets, including the capital stock and assets of ETP LLC and ETP GP and its ownership of 36.4 million ETP Common Units. The financial covenants contained in the revolving credit facility include a leverage ratio test, a consolidated leverage ratio test, a consolidated interest coverage ratio test and a value-to-loan ratio. Please see Note 6 to our consolidated financial statements included under Item 8 of this Form 10-K for further discussion of the covenants.

2005 Senior Secured Term Loan Agreement

On June 16, 2005, the Parent Company entered into a $600.0 million Senior Secured Term Loan Agreement with Goldman Sachs Credit Partners, L.P, with borrowings totaling $600.0 million. The Parent Company used approximately $175.5 million of the net proceeds from its IPO to repay a portion of indebtedness outstanding under its then existing $600.0 million term loan agreement. The remaining outstanding indebtedness was paid through approximately $4.5 million of cash on hand and approximately $420.0 million of borrowings under the Parent Company’s new $500.0 million credit facility (described above) which was entered into concurrently with the IPO. The Parent Company wrote off approximately $5.1 million in deferred financing costs to loss on extinguishment of debt in connection with the re-payment of the senior secured term loan agreement. The loans bore interest at an initial rate of LIBOR plus 3% subject to adjustment based upon a ratio of total debt to operating income. The loans were secured by the Parent Company’s ETP Common Units and General Partner interest in ETP.

On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.

 

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Energy Transfer Partners Indebtedness

On August 9, 2006 ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register up to $1.5 billion aggregate offering price of a combination of ETP Limited Partner interests and debt securities. On October 23, 2006, ETP closed the issuance, under its $1.5 billion S-3 registration statement, of $400 million of 6.125% senior notes due 2017 and $400 million of 6.625% senior notes due 2036, and received net proceeds of approximately $791 million. ETP used the proceeds to pay borrowings and accrued interest under its Revolving Credit Facility. Interest on the 2017 senior notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 senior notes is payable semiannually on April 15 and October 15 of each year, beginning April 15, 2007. The notes are unsecured senior obligations and will be fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries.

On April 10, 2006, ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register a $1.0 billion aggregate offering price of ETP Common Units representing its Limited Partner interests. Through August 31, 2006, ETP has not made any sales under this Registration Statement.

On November 23, 2005 ETP filed a registered exchange offer to exchange newly issued 5.65% Senior Notes due 2012 (the “2012 Notes”) that were registered under the Securities Act of 1933 (the “New Notes”), for a like amount of outstanding 5.65% Senior Notes due 2012, which had not been registered under the Securities Act (the “Old Notes”). On February 23, 2006 ETP commenced the exchange offer which closed on March 31, 2006. All $400.0 million of the Old Notes were tendered pursuant to the exchange offer and were replaced with a like amount of New Notes. The sole purpose of the exchange offer was to fulfill ETP’s obligations under the registration rights agreement entered into in connection with our sale of the Old Notes on July 29, 2005. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes.

2005 Senior Notes

ETC OLP and all of its direct and indirect wholly-owned subsidiaries act as the guarantor of the debt obligations for the 2015 Unregistered Notes issued on January 18, 2005 and the 2012 Notes issued on March 31, 2006. If ETP was to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. The ETP Senior Notes have equal rights to holders of ETP’s other current and future unsecured debt.

The Senior Notes represent ETP’s senior unsecured obligations and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. The Senior Notes are jointly and severally guaranteed by ETC OLP and all of the direct and indirect wholly 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 Senior Notes and each guarantee will effectively rank junior to any future indebtedness of ours or our subsidiary guarantors that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the 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 Senior Notes were issued under an indenture containing covenants, which include covenants that restrict our 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 our assts.

HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the Notes, we are required to pay an additional 1% per annum on the outstanding balance of the Notes at such time as the Notes are not rated investment grade status or higher. As of August 31, 2006 the Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Revolving Credit Facilities

ETP Facilities

On December 13, 2005, ETP entered into the $900.0 million ETP Revolving Credit Facility which replaced its existing Revolving Credit Facility. The ETP Revolving Credit Facility was amended on June 29, 2006 (the Amended and Restated Credit Agreement) allowing for borrowings up to $1.3 billion, expandable to $1.5 billion. The Amended and Restated Credit Agreement is available through June 29, 2011 unless ETP elects the two

 

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successive options (subject to bank approval) to extend the maturity date for a period of 364 days each. Amounts borrowed under the Amended and Restated Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Amended and Restated Credit Agreement has a Swingline loan option with a maximum borrowing of $75.0 million at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on ETP’s credit rating and the maximum fee is 0.175%. As of August 31, 2006, there was a balance of $1.2 billion in revolving credit loans (including $17.6 million in Swingline loans) and $14.4 million in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2006, was 6.04%. The total amount available under the Amended and Restated Revolving Credit Agreement, as of August 31, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $123.0 million. The Amended and Restated Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP and Titan and its wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On September 25, 2006 ETP exercised the accordion feature and expanded the total amount of the facility to $1.5 billion.

Prior to December 13, 2005, we had available a $800.0 million Revolving Credit Facility which bore interest at a rate based on either a Eurodollar rate, or a prime rate. The Revolving Credit Facility offered a Swingline loan option with the maximum borrowing of $30.0 million at a daily rate based on the London market. The weighted average interest rate was 4.827% at August 31, 2005. We borrowed $475.0 million under the Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of August 31, 2005, $201.0 million was outstanding under the Revolving Credit Facility which included $15.0 million under the Swingline option and also had outstanding Letters of Credit of $11.3 million. Per the previous agreement, Letter of Credit Exposure plus the Revolving Credit Facility could not exceed the $800.0 million maximum Revolving Credit Facility. Total amount available under the Credit Agreement at August 31, 2005 was $587.7 million.

On May 31, 2006, ETP entered into a $250.0 million Revolving Credit Facility, which matures under its terms on December 1, 2006. Amounts borrowed under this facility bear interest at a rate based on either a Eurodollar rate or a base rate. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The $250.0 million Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. The $250.0 million Revolving Credit Facility is unsecured and has equal rights to holders of ETP’s other current and future unsecured debt. On July 3, 2006, ETP reduced its borrowing capacity on the Revolving Credit Facility to $200.0 million. All terms and maturity date, as mentioned above, remain unchanged. There was $20.0 million outstanding on this facility as of August 31, 2006. The weighted average interest rate on the total amount outstanding at August 31, 2006 was 5.988%. This facility was paid and retired on October 18, 2006.

HOLP Facilities

Effective August 31, 2006, HOLP entered into the Fourth Amended and Restated Credit Agreement. The terms of the Agreement are as follows:

A $75.0 million Senior Revolving Facility is available through June 30, 2011. The revolving facility may be expanded to $150.0 million. The Facility has a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under this Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.955% for the amount outstanding at August 31, 2006. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The sum of the loans, swingline loans and letters of credit may not exceed the maximum amount of revolving credit. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Facility. As of August 31, 2006, the Facility had a balance outstanding of $20.0 million. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Senior Revolving Credit Facility. There were outstanding Letters of Credit of $1.0 million at August 31, 2006. The sum of the loans made under the Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 maximum amount of the Senior Revolving Facility.

Prior to August 31, 2006, HOLP also maintained a $75.0 million Senior Revolving Acquisition Facility for acquisition of propane-related businesses. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general

 

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intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. During the second quarter of fiscal year 2006, HOLP paid in full the outstanding indebtedness under this facility and cancelled the Senior Revolving Acquisition Facility.

Debt Covenants

The agreements for each of the Senior Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The most restrictive of these covenants require ETP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than 4.75 to 1 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. 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 our 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 HOLP 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 our bank credit facilities and the Note Agreements could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of August 31, 2006.

Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of August 31, 2006:

 

In thousands    Payments Due by Period

Contractual Obligations

   Total   

Less Than

1 Year

   1–3 Years    3–5 Years   

More Than

5 Years

Long-term debt

   $ 3,246,253    $ 40,607    $ 90,928    $ 1,723,131    $ 1,391,587

Interest on fixed rate long-term debt (a)

     614,499      90,145      170,029      155,581      198,744

Payments on derivatives

     38,646      36,918      1,728      —        —  

Purchase commitments (b)

     482,300      482,300      —        —        —  

Operating lease obligations

     49,178      8,809      16,946      13,789      9,634
                                  

Totals

   $ 4,430,876    $ 658,779    $ 279,631    $ 1,892,501    $ 1,599,965
                                  

(a) Fixed rate interest on long-term debt includes the amount of interest due on our fixed rate long-term debt. These amounts do not include interest on our variable rate debt obligations which include our Revolving Credit Facilities and, Revolving Credit Facility Swingline Loan options. As of August 31, 2006, variable rate interest on our outstanding balance of variable rate debt of $1.8 billion would be $115.3 million on an annual basis. See Note 6 – “Debt Obligations” to the consolidated financial statements beginning in Item 8 of this report for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt.
(b) We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We

 

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have long and short-term product purchase obligations for propane and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the August 31, 2006 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Quantities shown in the table represent our volume commitments and estimated payment obligations under these contracts for the periods indicated.

Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any 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 that is necessary or appropriate to provide for future cash requirements.

Distributions declared since the Parent Company’s Initial Public Offering in February 2006 are as follows:

 

     Record Date    Payment Date    Amount per Unit

Fiscal Year 2006

        
   March 31, 2006    April 19, 2006    $ 0.0578
   June 30, 2006    July 19, 2006    $ 0.2375

On September 25, 2006, the Parent Company announced the declaration of a cash distribution for the fourth quarter ended August 31, 2006 of $0.3125 per Common Unit, or $1.25 annually, an increase of $0.30 per Common Unit on an annualized basis. The distribution was paid on October 19, 2006 to Unitholders of record at the close of business on October 5, 2006.

The total amount of distributions (all from Available Cash from the Parent Company’s operating surplus) declared relating to the years ended August 31, 2006, 2005 and 2004 are as follows:

 

     2006    2005    2004

Limited Partners -

        

Limited Partners (a)

   $ 34,010    $ 666,751    $ 263,774

Common Units

     65,905      —        —  

Class B Units

     745      —        —  

General Partner

     599      4,861      2,503
                    

Total distributions declared

   $ 101,259    $ 671,612    $ 266,277
                    

(a) Represents distributions prior to the Parent Company’s IPO.

Cash Distributions Received by the Parent Company

Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s 2% general partner interest, 50% of ETP’s incentive distribution rights and ETP Common Units held by the Parent Company. As discussed above, we purchased the remaining 50% of ETP’s incentive distribution rights subsequent to August 31, 2006.

The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights of ETP for the years ended August 31, 2006, 2005 and 2004 are as follows:

 

     2006     2005     2004

Limited Partners Interests

   $ 80,203     $ 57,671     $ 20,411

General Partner Interest

     6,931       4,237       1,059

Incentive Distribution Rights

     64,436       27,971       2,890

Less holdbacks (a)

     (2,287 )     (8,182 )     —  
                      

Total distributions received from ETP

   $ 149,283     $ 81,697     $ 24,360
                      

(a) Represents amounts held back for reimbursement of expenses and contributions required to maintain ETP GP’s 2% General Partner interest in ETP.

 

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Cash Distributions Paid by ETP

ETP will use its cash provided by operating and financing activities from the Operating Partnerships to provide distributions to its Unitholders. Under ETP’s Partnership Agreement, ETP will 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 ETP’s 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 its operations. Heritage (the predecessor to ETP) paid all quarterly distributions since its inception in 1996 up to and including the quarterly distribution of $0.325 per unit paid on January 14, 2004. Heritage had raised its quarterly distribution over the years from $0.25 per unit in 1996 to $0.325 per unit as of the quarterly distribution paid on January 14, 2004.

Distributions declared by ETP during the years ended August 31, 2006, 2005 and 2004 are summarized as follows:

 

     Record Date    Payment Date    Amount per Unit

Fiscal Year 2006

        
   September 30, 2005    October 14, 2005    $ 0.5000
   January 4, 2006    January 13, 2006    $ 0.5500
   March 24, 2006    April 14, 2006    $ 0.5875
   June 30, 2006    July 14, 2006    $ 0.6375
   June 30, 2006 (1)    July 14, 2006    $ 0.0325

Fiscal Year 2005

        
   October 7, 2004    October 15, 2004    $ 0.4125
   January 5, 2005    January 14, 2005    $ 0.4375
   March 16, 2005    April 14, 2005    $ 0.4625
   July 8, 2005    July 14, 2005    $ 0.4875

Fiscal Year 2004

        
   April 2, 2004    April 14, 2004    $ 0.3500
   July 2, 2004    July 15, 2004    $ 0.3750

(1) Special SCANA distribution – On June 20, 2006, ETP announced that the Board of Directors of its General Partner declared a special distribution of $0.0325 per Limited Partner Unit related to the proceeds we received in connection with the SCANA litigation settlement (see Notes 7 and 10 to our consolidated financial statements). This distribution was paid on July 14, 2006 to the holders of record of ETP’s Common and Class F Units as of the close of business on June 30, 2006. This special one-time payment was approved following a determination of the Litigation Committee of ETP’s General Partner to distribute all the net distributable litigation proceeds we received in accordance with the Partnership Agreement. The special distribution also included a payment to the holder of ETP’s Class C Units for that amount normally allocated to its General Partner, which was $3.6 million.

On September 21, 2006, ETP announced the declaration of a cash distribution for the fourth quarter ended August 31, 2006 of $0.75 per Common Unit, or $3.00 annually, an increase of $0.45 per Common Unit on an annualized basis. The distribution was paid on October 16, 2006 to Unitholders of record at the close of business on October 5, 2006.

The total amount of distributions (all from Available Cash from ETP’s operating surplus) declared relating to the years ended August 31, 2006, 2005 and 2004 are as follows:

 

     2006    2005    2004

Limited Partners -

        

Common Units

   $ 248,237    $ 173,802    $ 52,963

Class D Units

     —        —        5,405

Class C Units (1)

     3,599      —        —  

Class F Units

     3,232      —        —  

General Partner -

        

2% Ownership

     6,981      4,390      1,392

Incentive Distribution Rights

     81,722      28,847      3,623
                    

Total distributions declared

   $ 343,771    $ 207,039    $ 63,383
                    

(1) Special SCANA distribution – see discussion above.

 

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New Accounting Standards

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We are currently evaluating the statement and have not yet determined the impact of such on our financial statements.

SFAS No. 151, Inventory Costs – an amendment of ARB No. 43, Chapter 4 (“SFAS 151”). In November 2004, the FASB issued SFAS 151 which amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing.” ARB No. 43 previously required that certain costs associated with inventory be treated as current period charges if they were determined to be so abnormal as to warrant it. SFAS 151 amends this removing the so abnormal requirement and stating that unallocated overhead costs and other items such as abnormal handling costs and amounts of wasted materials (spoilage) require treatment as current period charges rather than a portion of inventory cost. SFAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, with earlier application permitted. The provisions of this statement need not be applied to immaterial items. We do not allocate overhead costs to inventory and management has determined that there are no other material items which require the application of SFAS 151.

SFAS No. 154, Accounting Changes and Error Correction – a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). 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. Management will adopt the provisions of SFAS 154 beginning September 1, 2006, as applicable. 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.

SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140 (“SFAS 155”). SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Early application is permitted only if: (a) it occurs at the beginning of an entity’s fiscal year and (b) the entity has not yet issued any interim or annual financial statements for that fiscal year. We intend to adopt this statement when required at the start of fiscal year beginning September 1, 2008. The adoption of this statement is not expected to have a significant impact on us.

SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The FASB believes the standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other

 

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standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

EITF Issue No. 04-05, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights (“EITF 04-05”). EITF 04-05 provides guidance in determining whether a general partner controls a limited partnership by determining the limited partners’ substantive ability to dissolve (liquidate) the limited partnership as well as assessing the substantive participating rights of the limited partners within the limited partnership. EITF 04-05 states that if the limited partners do not have substantive ability to dissolve (liquidate) or have substantive participating rights, the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. This EITF is effective in fiscal periods beginning after December 15, 2005. We believe that our consolidation of ETP, ETP GP LP and ETP LLC complies with the provisions of EITF 04-05.

EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory With the Same Counterparty (“EITF 04-13”). In EITF 04-13, the Task Force reached a tentative conclusion that inventory purchases and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying Accounting Principles Board Opinion No. 29, “Accounting for Nonmonetary Transactions.” The tentative conclusions reached by the Task Force are required to be applied to transactions completed in reporting periods beginning after March 15, 2006. We adopted this EITF during fiscal year 2006 and such adoption did not have a material impact on our results of operations, financial position or cash flows.

EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (that is, Gross Versus Net Presentation) (“EITF 06-3”). This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). This guidance is effective for interim and annual reporting periods beginning after December 15, 2006 with earlier application permitted. As a matter of policy, we report such taxes on a net basis. We will adopt this EITF during our 2007 fiscal year.

Critical Accounting Policies and Estimates

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 – “Significant Accounting Policies and Balance Sheet Detail” to our consolidated financial statements in this report.

 

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Use of 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. As is normal in the natural gas industry, our most current month’s financial results for our midstream and transportation and storage segments are estimated using volume estimates and market prices. Actual results could differ from our estimates if the underlying assumptions prove to be incorrect.

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. We generate midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, we receive 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 our systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in our 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, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, we provide 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. Our 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.

Our transportation and storage segment results are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our 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 us 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, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. The transportation and storage segment also generates its revenues and margin from the sale and marketing of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL system.

We account for our trading activities under the provisions of EITF Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF 02-3”), which requires revenue and costs related to energy trading contracts to be presented on a net basis in the income statement.

Fair Value of Derivative Commodity Contracts. We utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices and in our trading activities. These contracts consist primarily of commodity forwards, futures, swaps, options and certain basis contracts as cash flow hedging instruments. Certain contracts are not accounted for as hedges and, in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), the gains and losses resulting from changes in the fair value of these contracts are recorded on a current basis on the statement of operations. In our retail propane business, we classify all gains and losses from these derivative contracts entered into for risk management purposes as liquids marketing revenue in the consolidated statement of operations. The gains and losses on the natural gas derivative contracts that are entered into for trading purposes are recognized in the midstream and transportation and storage revenue on a net basis in the consolidated statement of operations. The non-trading gains and losses for natural gas contracts are recorded as cost

 

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of products sold in the consolidated statement of operations. On our contracts that are designated as cash flow hedges 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 physical transaction settles. The ineffective portion of the gain or loss is reported in earnings immediately. We utilize 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. We also use the Black-Scholes valuation model to estimate the value of certain options. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

Natural Gas Exchanges. We record exchange receivables and payables when a customer delivers more or less gas into our pipelines than they take out. We primarily estimate the value of our exchanges at prices representing the value of the commodity at the end of the accounting reporting period. Changes in natural gas prices may impact our valuation. Based on our net payable position of $1.5 million as of August 31, 2006, a change in natural gas prices of 10 percent could positively or negatively affect our results of operations by $0.2 million.

Volume Measurement. We record 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 our business.

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, we 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.

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 our systems in order to maintain or increase throughput on our existing assets. Growth or expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur 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. We do not anticipate future changes in the estimated useful live of our property, plant, and equipment.

Amortization of Intangible Assets. For those intangible assets that do not have indefinite lives, we calculate amortization using the straight-line method over periods ranging from 2 to 15 years. We use amortization methods and determine asset values based on management’s best estimate using reasonable and supportable assumptions and projections. Changes in the amortization methods, asset values or estimated lives could have a material effect on our results of operations. We do not anticipate future changes in the estimated useful lives of our intangible assets.

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.

 

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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. We have determined that we are obligated by contractual or regulatory requirements to remove assets or perform other remediation upon retirement of certain assets. However, the fair value of our asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. We will record an asset retirement obligation in the periods in which it can reasonably determine the settlement dates.

Income Per Limited Partner Unit. Basic net income per limited partner unit is computed in accordance with EITF Issue No. 03-6 (“EITF 03-6”) Participating Securities and the Two-Class method under FASB Statement No. 128, by dividing limited partners’ interest in net income by the weighted average number of Common and Class B Units outstanding. In periods when our aggregate net income exceeds the aggregate distributions, EITF 03-6 requires us to present earnings per unit as if all of the earnings for the periods were distributed, see Note 4 – “Net Income Per Limited Partner Unit” to our consolidated financial statements. Diluted net income per limited partner unit is computed by dividing limited partners’ interest in net income, after considering the General Partner’s interest, by the weighted average number of Common and Class B Units outstanding and the effect of non-vested restricted units (“Unit Grants”), if any.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risks related to interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell in our midstream, transportation and storage activities. We control the scope of risk management, marketing and trading activities through a comprehensive set of policies and procedures involving senior levels of management. The audit committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. A risk oversight committee, comprised of the Co-Chief Executive Officers, Chief Financial Officer, Treasurer, President of our midstream and transportation and storage operations, Controller of our midstream and transportation and storage operations, and Senior Vice President – Commercial Optimization of our midstream and transportation and storage operations, sets forth risk management policies and objectives. The committee establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The trading activities are subject to the commodity risk management policy that includes risk management limits, including volume and stop-loss limits, to manage exposure to market risk.

In our retail propane business, the market price of propane is often subject to volatility changes as a result of supply or other market conditions over which we have no control. In the past, price changes have generally been passed along to our propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to us during periods of high demand, we 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. The propane is then stored at both our customer service locations and in major storage facilities for future resale.

Non-trading Activities

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow us to protect our 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 us to the risk of financial loss in certain circumstances, including instances when 1) sales volumes are less than expected, or 2) our counterparties fail to purchase the contracted quantities of natural gas or propane or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly protected against decreases in such prices on hedged transactions.

 

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We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in prices. However, we are subject to counterparty risk for both the physical and financial contracts. We also utilize forward purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. We account for such physical contracts under the “normal purchases and sales exception” of SFAS 133.

In connection with the acquisition of HPL, we acquired certain physical forward contracts that contain embedded options that we have not designated as a normal purchase and sale nor were the contracts 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 our consolidated balance sheet as a component of price risk management assets and liabilities.

In our midstream and transportation and storage segments, we account for certain of our derivatives as cash flow hedges under SFAS 133. All derivatives are recognized on the balance sheet at fair value as price risk management assets and liabilities. The changes in the fair value of price risk management assets and liabilities that are designated, 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. For those derivatives 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.

We also attempt to maintain balanced positions in our midstream and transportation and storage segments to protect us from the volatility in the energy commodities markets. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results either favorably or unfavorably.

Trading Activities

We have a risk management policy that provides for our marketing and trading operations to execute limited strategies. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis and gas daily contracts. These instruments are within the guidelines of the risk management policy which has been approved by our Board of Directors. The trading activities are a compliment to the producer services’ operations and are accounted for in net revenues on the consolidated statement of operations. We follow the applicable provisions of EITF Issue 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 consolidated statement of operations as other revenue. Changes in the assets and liabilities from the trading activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. Forward physical contracts associated with the trading activities are marked to market and included in revenue on our consolidated statement of operations because they do not meet “normal purchases and sales exception” of SFAS 133.

Commodity-related Derivatives

Our commodity-related price risk management assets and liabilities as of August 31, 2006 were as follows:

 

      Commodity    Notional
Volume
MMBTU
  Maturity    Fair
Value
 

Mark to Market Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    33,711,140   2006-2009    $ (6,247 )

Swing Swaps IFERC

   Gas    (37,220,448)   2006-2008      2,618  

Fixed Swaps/Futures

   Gas    3,607,500   2006-2007      (170 )

Forward Physical Contracts

   Gas    (7,986,000)   2006-2008      (21,653 )

Options

   Gas    (1,046,000)   2006-2008      21,653  

Forwards/Swaps (in Gallons)

   Propane    24,066,000   2006-2007      199  

(Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (2,572,500)   2006-2008      21,995  

Swing Swaps IFERC

   Gas    —     2006      (31 )

Forward Physical Contracts

   Gas    (455,000)   2006      (68 )

Cash Flow Hedging Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (34,585,000)   2006-2007      (2,987 )

Fixed Swaps/Futures

   Gas    (37,872,500)   2006-2007      2,043  

 

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Credit Risk

We maintain credit policies with regard to our counterparties that we believe significantly minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies (“LDCs”). This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

Sensitivity analysis

The table below summarizes our commodity-related financial positions and values as of August 31, 2006. The table assumes a hypothetical 10% change in the underlying price of the commodity and its effect.

 

    

Notional

Volume

MMBTU

    Fair
Value
   

Effect of

Hypothetical

10% Change

Non-Trading Derivatives

      

Fixed Swaps/Futures

   (34,265,000 )   $ 1,873     $ 42,615

Basis Swaps IFERC/NYMEX

   (873,860 )     (9,234 )     1,594

Swing Swaps IFERC

   (37,220,448 )     2,618       514

Options

   (1,046,000 )     21,653       5,189

Forward Physical Contracts

   (7,986,000 )     (21,653 )     5,189

Propane Forwards/Swaps (in Gallons)

   24,066,000       199       2,766

Trading Derivatives

      

Swing Swaps IFERC

   —         (31 )     205

Basis Swaps IFERC/NYMEX

   (2,572,500 )     21,995       701

Forward Physical Contracts

   (455,000 )     (68 )     75

The table below summarizes our positions and values as of August 31, 2005. The table assumes a hypothetical 10% change in the underlying price of the commodity and its effect.

 

    

Notional

Volume

MMBTU

    Fair Value    

Effect of

Hypothetical

10% Change

Nymex Futures/ Fixed Price

   (43,937,500 )   $ (148,006 )   $ 51,962

Basis Swaps

   (96,846,114 )     53,840       9,788

Fixed Price Index Swaps

   5,910,000       36,455       6,472

Options

   (1,776,000 )     78,941       16,034

Swing Swaps

   (67,841,503 )     (10,085 )     1,428

Forward Contracts

   (21,340,000 )     (78,500 )     16,034

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10 percent change (increase or

 

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decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or in accumulated other comprehensive income. In the event of an actual 10 percent change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10 percent due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps).

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our variable rate debt and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At August 31, 2006, we had a total of $1.8 billion of variable rate debt outstanding of which $1.5 billion is not hedged. A hypothetical change of 100 basis points in the underlying interest rate would have an effect of $181.9 million in increased interest expense on an annual basis.

Treasury locks with a notional amount of $100.0 million were outstanding as of August 31, 2006 and had a fair value of $0.1 million which was recorded as a component of price risk management assets on the consolidated balance sheet. A hypothetical change of 100 basis points on the underlying interest rates of the treasury locks outstanding at August 31, 2006 would have an effect of $8.0 million on the value of the locks. Forward starting interest rate swaps with a notional amount of $600.0 million were also outstanding as of August 31, 2006 and had a fair value of $8.2 million which was recorded as a component of price risk management liabilities on the consolidated balance sheet. A hypothetical change of 100 basis points on the underlying interest rates of the interest rate swaps outstanding as of August 31, 2006 would have an effect of $47.0 million on the value of the swaps. In connection with the Titan acquisition, we assumed a three year LIBOR interest swap with a notional amount of $125.0 million. The fair value of this swap at August 31, 2006 was approximately $0.5 million. A hypothetical change of 100 basis points on the underlying interest rate would have an effect of $2.9 million on the value of the swap.

The Parent Company had interest rate swaps with a notional amount of $300.0 million outstanding as of August 31, 2006 and had a net fair value of $(0.4) million which was recorded as a component of price risk management assets and liabilities on the consolidated balance sheets. A hypothetical change of 100 basis points on the underlying interest rates of the interest rate swaps outstanding at August 31, 2006 would have an effect of $22.4 million on the value of the swaps.

We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we 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.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

 

     Page

Report of Independent Registered Public Accounting Firm

   83

Consolidated Balance Sheets – August 31, 2006 and 2005

   84

Consolidated Statements of Operations – Years Ended August 31, 2006, 2005, and 2004

   86

Consolidated Statements of Comprehensive Income (Loss) – Years Ended August 31, 2006, 2005, and 2004

   87

Consolidated Statements of Partners’ Capital (Deficit) – Years Ended August 31, 2006, 2005, and 2004

   88

Consolidated Statements of Cash Flows – Years Ended August 31, 2006, 2005, and 2004

   89

Notes to Consolidated Financial Statements

   90

 

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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. (a Delaware limited partnership) and subsidiaries, as of August 31, 2006 and 2005 and the related consolidated statements of operations, comprehensive income, partners’ capital (deficit), and cash flows for each of the three years in the period ended August 31, 2006. 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 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 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, 2006 and 2005 and the results of their operations and their cash flows for each of the three years in the period ended August 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

November 20, 2006 (except for Note 18, as to which the date is November 28, 2006)

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

 

    

August 31,

2006

  

August 31,

2005

ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 26,204    $ 33,459

Marketable securities

     2,817      3,452

Accounts receivable, net of allowance for doubtful accounts

     675,545      847,028

Accounts receivable from related companies

     602      2,295

Inventories

     387,140      291,445

Deposits paid to vendors

     87,806      65,034

Exchanges receivable

     23,221      35,623

Price risk management assets

     56,851      138,961

Prepaid expenses and other

     42,549      36,433
             

Total current assets

     1,302,735      1,453,730

PROPERTY, PLANT AND EQUIPMENT, net

     3,748,614      2,887,750

LONG-TERM PRICE RISK MANAGEMENT ASSETS

     2,192      41,687

ADVANCES TO AND INVESTMENT IN AFFILIATES

     41,344      37,353

GOODWILL

     633,998      353,608

INTANGIBLES AND OTHER ASSETS, net

     185,735      118,091

OTHER LONG-TERM ASSETS

     9,523      13,453
             

Total assets

   $ 5,924,141    $ 4,905,672
             

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

 

    

August 31,

2006

   

August 31,

2005

 
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)     

CURRENT LIABILITIES:

    

Working capital facility

   $ —       $ 17,026  

Accounts payable

     603,527       818,810  

Accounts payable to related companies

     320       410  

Exchanges payable

     24,722       33,772  

Customer advances and deposits

     108,836       138,442  

Accrued and other current liabilities

     205,228       90,114  

Price risk management liabilities

     36,918       104,772  

Income taxes payable

     —         2,063  

Deferred income taxes

     629       —    

Current maturities of long-term debt

     40,607       39,376  
                

Total current liabilities

     1,020,787       1,244,785  

LONG-TERM DEBT, less current maturities

     3,205,646       2,275,965  

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES

     2,843       30,517  

LONG-TERM PAYABLE TO AFFILIATE

     —         2,005  

DEFERRED INCOME TAXES

     207,877       215,118  

OTHER NON-CURRENT LIABILITIES

     2,110       13,284  

MINORITY INTERESTS

     1,439,127       1,212,135  

COMMITMENTS AND CONTINGENCIES (Note 10)

    
                

Total liabilities

     5,878,390       4,993,809  
                

PARTNERS’ CAPITAL (DEFICIT):

    

General Partner

     (69 )     772  

Limited Partners -

    

Common Unitholders (124,360,520 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)

     (9,586 )     —    

Class B Unitholders (2,521,570 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)

     53,130       —    

Limited partners’ deficit (0 and 136,357,870 limited partner units issued and outstanding at August 31, 2006 and 2005, respectively)

     —         (62,216 )
                
     43,475       (61,444 )

Accumulated other comprehensive income (loss)

     2,276       (26,693 )
                

Total partners’ capital (deficit)

     45,751       (88,137 )
                

Total liabilities and partners’ capital (deficit)

   $ 5,924,141     $ 4,905,672  
                

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)

 

    

Year Ended

August 31, 2006

   

Year Ended

August 31, 2005

   

Year Ended

August 31, 2004

 

REVENUES:

      

Midstream and transportation and storage

   $ 6,877,512     $ 5,383,625     $ 1,966,803  

Propane

     893,647       709,904       342,523  

Other

     87,937       75,269       37,631  
                        

Total revenues

     7,859,096       6,168,798       2,346,957  
                        

COSTS AND EXPENSES:

      

Cost of products sold – midstream and transportation and storage

     5,963,422       4,911,366       1,771,321  

Cost of products sold – propane

     580,978       448,853       199,640  

Cost of products sold – other

     23,916       21,296       10,463  

Operating expenses

     422,989       319,554       147,374  

Depreciation and amortization

     129,636       105,751       56,242  

Selling, general and administrative

     162,615       64,057       31,111  
                        

Total costs and expenses

     7,283,556       5,870,877       2,216,151  
                        

OPERATING INCOME

     575,540       297,921       130,806  

OTHER INCOME (EXPENSE):

      

Interest expense, net of interest capitalized

     (150,646 )     (101,061 )     (41,217 )

Loss on extinguishment of debt

     (5,060 )     (6,550 )     —    

Equity in earnings (losses) of affiliates

     (479 )     (376 )     363  

Gain (loss) on disposal of assets

     851       (330 )     (1,006 )

Gain on Energy Transfer Transactions

     —         —         395,253  

Interest and other income, net

     13,701       12,191       516  
                        

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS

     433,907       201,795       484,715  

Income tax expense

     (23,015 )     (4,397 )     (2,792 )
                        

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS

     410,892       197,398       481,923  

Minority interests

     (303,752 )     (96,946 )     (35,164 )
                        

INCOME FROM CONTINUING OPERATIONS

     107,140       100,452       446,759  
                        

DISCONTINUED OPERATIONS:

      

Income from discontinued operations

     —         5,498       6,163  

Gain on sale of discontinued operations, net of income tax expense

     —         106,092       —    

Minority interest in income from discontinued operations

     —         (65,296 )     (2,705 )
                        

Total income from discontinued operations

     —         46,294       3,458  
                        

NET INCOME

     107,140       146,746       450,217  

GENERAL PARTNER’S INTEREST IN NET INCOME

     609       1,207       4,438  
                        

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 106,531     $ 145,539     $ 445,779  
                        

BASIC NET INCOME PER LIMITED PARTNER UNIT

      

Limited Partners’ income from continuing operations

   $ 0.80     $ 0.89     $ 4.54  

Limited Partners’ income from discontinued operations

     —         0.41       0.04  
                        

NET INCOME PER LIMITED PARTNER UNIT

   $ 0.80     $ 1.30     $ 4.58  
                        

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING

     133,820,176       111,939,537       97,474,988  
                        

DILUTED NET INCOME PER LIMITED PARTNER UNIT

      

Limited Partners’ income from continuing operations

   $ 0.79     $ 0.75     $ 3.35  

Limited Partners’ income from discontinued operations

     —         0.34       0.03  
                        

NET INCOME PER LIMITED PARTNER UNIT

   $ 0.79     $ 1.09     $ 3.38  
                        

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING

     133,820,176       132,795,472       131,923,251  
                        

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

 

    

For the Year

Ended