Form 10-K
Table of Contents
Index to Financial Statements

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, 2007

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.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(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  x    No  ¨

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.  ¨

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. (Check one.)

Large accelerated filer  x    Accelerated filer  ¨    Non accelerated filer  ¨

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, 2007, 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 $3,030,100,000. 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 October 15, 2007, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P.         222,829,956 Common Units

Documents Incorporated by Reference: None

 



Table of Contents
Index to Financial Statements

ENERGY TRANSFER EQUITY, L.P.

2007 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

          PAGE
   PART I   
ITEM 1.    BUSINESS    2
ITEM 1A.    RISK FACTORS    21
ITEM 1B.    UNRESOLVED STAFF COMMENTS    47
ITEM 2.    PROPERTIES    47
ITEM 3.    LEGAL PROCEEDINGS    48
ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS    51
   PART II   
ITEM 5.    MARKET FOR THE REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES    51
ITEM 6.    SELECTED FINANCIAL DATA    53
ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    54
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    85
ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA    90
ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    160
ITEM 9A.    CONTROLS AND PROCEDURES    160
ITEM 9B.    OTHER INFORMATION    163
   PART III   
ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT    163
ITEM 11.    EXECUTIVE COMPENSATION    167
ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS    182
ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE    183
ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES    184
   PART IV   
ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES    185


Table of Contents
Index to Financial Statements

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.

Definitions

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
Capacity    Capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels.
Dekatherm    Million British thermal units. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.
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.
Wobbe    A number representing the interchange ability of fuel gases – an indicator of the similarity between a specific natural gas and propane-air mixture.

 

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Index to Financial Statements

ITEM 1. BUSINESS

Overview

We are a publicly traded Delaware 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. The Parent Company’s direct and indirect ownership of ETP consist of approximately 62.5 million Common Units, the 2% General Partner interests and 100% of the Incentive Distribution Rights. 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.

Currently, the Parent Company’s business operations are conducted only through ETP’s wholly-owned subsidiary operating partnerships (collectively referred to as the “Operating Partnerships”). The activities in which we are engaged, all of which are in the United States, and the Operating Partnerships through which we conduct those activities are as follows:

 

 

Natural gas operations, consisting of the following segments:

 

   

natural gas midstream and intrastate transportation and storage through La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”),

 

   

interstate natural gas transportation services through Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”);

 

 

Retail propane through Heritage Operating, L.P (“HOLP”) and Titan Energy Partners, L.P. (“Titan”).

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.

Significant Fiscal Year 2007 Achievements

Our significant fiscal year 2007 achievements included the following, as discussed in more detail herein:

 

 

The Parent Company received distributions from ETP of $175.0 million, $12.7 million and $183.1 million related to its limited partner interests, general partner interests and Incentive Distribution Rights, respectively.

 

 

On a consolidated basis, we had revenues of approximately $7.0 billion, operating income of approximately $810.0 million and net income of approximately $319.0 million. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

The acquisition of the Transwestern pipeline on December 1, 2006. See Note 2 to our consolidated financial statements.

 

 

The execution of an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). See Note 3 to our consolidated financial statements.

 

 

Completion of the Cleburne to Carthage pipeline.

 

 

Began construction of the Southeast Bossier pipeline, approximately 157 miles of predominately 42-inch pipe connecting our East Texas and Cleburne to Carthage pipelines with the Texoma pipeline (which is a part of our HPL System) north of Beaumont, Texas, which we expect to complete by the second calendar quarter of 2008.

 

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Index to Financial Statements
 

Began construction of the Paris Loop pipeline, a 135 mile pipeline connecting our existing pipelines in the Barnett Shale region to our Texoma pipeline in Lamar County, Texas, which we expect to complete in the second calendar quarter of 2008.

 

 

Initiation of the Phoenix project, a planned expansion of the Transwestern pipeline.

 

 

Completion of the first phase of the natural gas processing plant in Godley, Texas.

Other Developments

On May 7, 2007, Ray Davis, previously the Co-Chairman and Co-Chief Executive Officer of ETP (see below), and Natural Gas Partners VI, L.P. (“NGP”) and affiliates of each, sold approximately 38.9 million Common Units of ETE (17.6% of the outstanding Common Units of ETE) to Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”). In addition to the purchase of ETE Common Units, Enterprise also acquired a 34.9% non-controlling equity interest in the General Partner of ETE, LE GP, L.L.C. (“LE GP”). As a result of these transactions, EPE and its subsidiaries are considered related parties (see Note 12 of our consolidated financial statements).

Ray C. Davis, previously the Co-Chief Executive Officer and Co-Chairman of ETP, and Co-Chairman of ETE, retired from these positions effective as of August 15, 2007. As a result of Mr. Davis’ retirement, Kelcy L. Warren, formerly Co-Chief Executive Officer and Co-Chairman of ETP and Co-Chairman of ETE, became the sole Chief Executive Officer and Chairman of ETP and sole Chairman of ETE upon the effective date of Mr. Davis’ retirement. Mr. Davis will continue to serve as a director of ETP and ETE.

ETP Operations

Segment Overview and Business Description

Our segments and business are as described below. See Notes 1 and 14 to our consolidated financial statements for additional segment information and the financial information of our segments for our fiscal years ended August 31, 2007, 2006 and 2005.

Natural Gas Operations

The following map depicts the major components of our natural gas operations:

LOGO

 

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Index to Financial Statements

Midstream

Southeast Texas System

 

 

4,300 miles of natural gas pipeline

 

 

1 natural gas processing plant (the LaGrange plant) with aggregate capacity of 240 MMcf/d

 

 

5 natural gas treating facilities with aggregate capacity of 720 MMcf/d

 

 

3 natural gas conditioning facilities with aggregate capacity of 450 MMcf/d

North Texas System

 

 

160 miles of natural gas pipeline

 

 

1 natural gas processing plant (the Godley plant) with current capacity of approximately 300 MMcf/d and construction in progress to increase the aggregate processing capacity to approximately 500 MMcf/d

 

 

1 natural gas conditioning facility with capacity of 100 MMcf/d

Canyon Gathering System (acquired October 2007)

 

 

1,800 miles of natural gas pipeline

 

 

6 natural gas conditioning facilities with aggregate capacity of 90 MMcf/d

Intrastate Transportation Pipelines and Storage Facilities

ET Fuel System

 

 

Capacity of 3.1 Bcf/d

 

 

2,200 miles of natural gas pipeline

 

 

2 storage facilities with 12.4 Bcf of total working capacity

Oasis pipeline

 

 

Capacity of 1.2 Bcf/d

 

 

583 miles of natural gas pipeline

 

 

Connects Waha to Katy market hubs

Houston pipeline system (“HPL System”)

 

 

Capacity of 4.4 Bcf/d

 

 

4,400 miles of natural gas pipeline

 

 

6 natural gas treating facilities with aggregate capacity of 280 MMcf/d

 

 

Bammel storage facility with 62 Bcf of total working capacity

East Texas pipeline

 

 

Capacity of 740 MMcf/d

 

 

168 miles of natural gas pipeline

Interstate Transportation Pipelines

Transwestern pipeline (acquired December 2006)

 

 

Capacity of 2.1 Bcf/d

 

 

2,400 miles of interstate natural gas pipeline

Midcontinent Express Pipeline

 

 

Initial planned capacity of 1.4 Bcf/d

 

 

500 miles of interstate natural gas pipeline

 

 

50/50 joint venture with Kinder Morgan

 

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Index to Financial Statements

Our Midstream Operations

Our midstream business owns and operates approximately 6,260 miles of in service natural gas gathering pipelines, three natural gas processing plants, five natural gas treating facilities, and ten natural gas conditioning facilities. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas, and our operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas, the Bossier Sands in east Texas, and the Uinta and Piceance Basins in Utah and Colorado.

The midstream segment accounted for approximately 15% of our total consolidated operating income for the year ended August 31, 2007. 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 we generate income from limited trading activities, principally from the use of derivatives, in accordance with our commodity risk management policy. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk”.

Our midstream segment consists of the following:

 

 

The Southeast Texas System, a 4,300-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, five treating facilities and three conditioning facilities. This system is connected to the Katy Hub through the 168-mile East Texas pipeline and is also connected to the Oasis pipeline, as well as two power plants.

The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through our system to produce residue gas and NGLs. The plant has a processing capacity of approximately 240 MMcf/d. Our five treating facilities have an aggregate capacity of 700 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. Our three conditioning facilities have an aggregate capacity of 450 MMcf/d. These conditioning facilities remove heavy hydrocarbons from the gas gathered into our systems so the gas can be redelivered and meet downstream pipeline hydrocarbon dew point specifications.

 

 

The North Texas System, a 160-mile integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett Shale trend. The system includes our Godley plant, as discussed below.

The Godley plant was built in two phases to process rich natural gas produced from the Barnett Shale and is connected with the North Texas System and the ET Fuel System. The facility consists of a cryogenic processing plant with processing capacity of approximately 300 MMcf/d. Construction is in progress to increase the aggregate processing capacity to approximately 500 MMcf/d. Construction is scheduled to be completed in the third calendar quarter of 2008.

 

 

The Canyon Gathering System consists of approximately 1,800 miles of gathering pipeline ranging in diameters from two inches to 16 inches in the Piceance-Uinta Basin of Colorado and Utah and six conditioning plants with an aggregated processing capacity of 90 MMcf/d. The system currently gathers approximately 130,000 MMBtu/d from 1,400 wells and is connected to five major pipeline systems.

 

 

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 550 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.

 

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Index to Financial Statements

Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or our intrastate 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 Intrastate Transportation and Storage Operations

Our intrastate transportation and storage business owns and operates approximately 7,500 miles of natural gas transportation pipelines, three natural gas storage facilities and six natural gas treating facilities.

Through ETC OLP, we own the largest intrastate pipeline system in the United States with interconnects to major consumption areas throughout the United States. Our intrastate 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 natural gas pipeline and storage assets that are referred to as the ET Fuel System, and our HPL System, which are described below.

Our intrastate transportation and storage operations accounted for approximately 59% of our total consolidated operating income for the year ended August 31, 2007. The results from our intrastate 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, we purchase natural gas from either the market (including purchases from our midstream segment’s producer services) or 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 based on an index price.

We also utilize our Bammel storage facility to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We generally 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.

Our intrastate transportation and storage segment consists of the following:

 

 

The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,200 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 near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in east Texas, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 3.3 Bcf/d of natural gas and total working storage capacity of 12.4 Bcf of natural gas.

The ET Fuel System also 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. Included in the ET Fuel System is a significant portion of our recently completed Cleburne to Carthage pipeline that connects our North Texas pipeline (“NTP”), a part of our ET Fuel System, our pipelines in the Barnett Shale region, and our Bethel storage facility to our Texoma pipeline in East Texas.

In addition, the ET Fuel System is connected with our Godley plant. This gives us the ability to bypass the plant when processing margins are unfavorable by blending the un-treated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

 

 

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.

 

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Index to Financial Statements

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 HPL System is comprised of approximately 4,400 miles of intrastate natural gas pipeline with an aggregate capacity of 4.4 Bcf/d, six treating facilities with aggregate capacity of 280 MMcf/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 HPL System also includes 32 miles of the Cleburne to Carthage pipeline from our Texoma pipeline interconnect to the Carthage Hub. The HPL 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 HPL 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 62 Bcf and has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that the HPL 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.

On October 9, 2007, we announced our plan to expand our Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub (the “Carthage Loop”), adding an additional 500 MMcf/d of capacity to the Carthage Hub. The Carthage Loop is expected to be in service by the third calendar quarter of 2008.

 

 

The East Texas pipeline is a 168-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.

On October 9, 2007, we announced an expansion (the “Katy expansion”) of our East Texas pipeline with the installation of 56 miles of 36-inch pipeline and the addition of 20,000 horsepower of compression. The Katy expansion will increase the capacity on the East Texas pipeline from approximately 700 MMcf/d to more than 1.1 Bcf/d and is expected to be in service by the third calendar quarter of 2008.

Interstate Transportation Operations

Our interstate transportation segment accounted for approximately 12% of our total consolidated operating income for the year ended August 31, 2007. The results from our interstate transportation segment are primarily derived from the fees earned from natural gas transportation services and operational gas sales. Our interstate transportation operation began in fiscal 2007 with the acquisition of the Transwestern pipeline.

 

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Index to Financial Statements

Our interstate transportation segment consists of the following:

 

 

The Transwestern pipeline, an open-access natural gas interstate pipeline extending approximately 2,400 miles from the gas producing regions of West Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern pipeline has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets like Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC, which regulates our interstate natural gas pipeline interests (see “The Midstream and Transportation and Storage Segments – Regulation”). The operating results for Transwestern are included in our results on a consolidated basis as of the acquisition date (December 1, 2006).

During fiscal year 2007, we initiated the Phoenix project, consisting of 260 miles of 42-inch and 36-inch pipeline lateral, with a throughput capacity of 500 MMcf/d, connecting the Phoenix area to Transwestern’s existing mainline at Ash Fork, Arizona and approximately 25 miles of 36-inch pipeline looping of Transwestern’s existing San Juan lateral, adding 375 MMcf/d of capacity. Transwestern filed with the Federal Energy Regulatory Commission (“FERC”) for a certificate of public convenience and necessity on September 15, 2006 in Docket No. CP06-459. The final Environmental Impact Statement was issued by FERC on September 21, 2007. A final FERC certificate is expected in fall 2007, with construction beginning immediately thereafter. The project is expected to be partially in-service in the third calendar quarter of 2008 and completely in-service in the fourth calendar quarter of 2008.

 

 

A joint development with Kinder Morgan Energy Partners, L.P. for our 50% interest in MEP, an approximately 500-mile interstate natural gas pipeline scheduled to be in service during the second calendar quarter of 2009, that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, that transports natural gas to the significant natural gas markets in the northeast portion of the United States. As of and for the year ended, August 31, 2007, the activity related to MEP was not material to our consolidated results of operations, financial position or cash flows.

Retail Propane Operations

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 approximately 440 customer service locations in approximately 40 states. Our propane operations extend from coast to coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. Our propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth.

Our retail propane operations accounted for approximately 15% of our total consolidated operating income for the year ended August 31, 2007. The retail propane segment is a margin-based business 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. 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.

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 segment 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. 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 commercial and industrial 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

 

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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.

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. 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.

Business Strategy and Competitive Strengths

The Parent Company Business Strategy

Our current 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 and Strengths

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 natural gas operations and retail propane business, we will be best positioned to achieve our objectives.

We expect that acquisitions in our natural gas operations will be the primary focus of our acquisition strategy going forward, as evidenced by our acquisition of the Transwestern pipeline and Canyon Gathering 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 natural gas operations will provide internal growth projects of greater scale compared to those available in our propane business, as demonstrated by our Cleburne to Carthage pipeline, the Phoenix project and other recently announced projects.

We believe that we are well-positioned to compete in both the natural gas operations and retail 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 will increase our financial flexibility and enhance 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.

 

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Natural Gas Operations 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 under long-term producer commitments, 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 and transportation services. These projects include those discussed above and include the construction of the Cleburne to Carthage pipeline, the Phoenix project, the expansion of the processing capacity at our Godley plant, and our Southeast Bossier pipeline connecting the Barnett Shale to our Texoma pipeline. We expect that these expansions will lead to additional growth opportunities in this area.

Increase cash flow from fee-based businesses. Excluding results from our marketing activities, the portion of our gross margin in our natural gas operations 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. We intend to continue to make strategic acquisitions of midstream, transportation and storage assets in our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets. As demonstrated by our acquisitions of the Transwestern pipeline and the Canyon Gathering System, 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, with growing demand for natural gas or that otherwise provide the opportunity to provide our customers with increased flexibility to transport natural gas from additional supply basins and additional markets.

Natural Gas Operations Business Strengths

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 System acquisition in January 2005, and the completion of the East Texas 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 Cleburne to Carthage pipeline and other related projects provides 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 provide producers with additional firm access to west coast markets with the acquisition of the Transwestern pipeline.

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 such as the Barnett Shale. We expect the acquisition of the Transwestern pipeline will provide us with market presence in other prolific gas-producing regions in the western United States. We also expect the acquisition of the Canyon Gathering System will provide us with market presence in the Piceance-Uinta Basins in Colorado and Utah.

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 and Godley processing plants reduces our commodity price risk. A significant benefit of our ownership of the Oasis pipeline and ET Fuel System is that we can elect not to process natural gas at our processing plants 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 or North Texas

 

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System with lean gas, or gas with a low NGL content, transported on the Oasis pipeline or ET Fuel System. 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 HPL 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 HPL System, has a total working gas capacity of approximately 62 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the HPL 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 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.

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.

 

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Natural Gas Operations Segments

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 2007 annual outlook, total domestic consumption of natural gas is expected to increase from an estimated 22.0 Tcf consumed in 2005 to 26.1 Tcf in 2030. During the five-year period ended December 31, 2006, the United States has on average consumed approximately 22.3 Tcf per year, with average domestic production of approximately 23.8 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.

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.

 

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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.

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 could be significant to our overall profitability.

During the year ended August 31, 2007, none of our customers individually accounted for more than 10% of midstream, intrastate transportation and storage and interstate segment revenues.

Regulation

Regulation by FERC of Interstate Natural Gas Pipelines. Under the Natural Gas Act (“NGA”), FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” service includes storage service. The Transwestern pipeline transports natural gas in interstate commerce and thus qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. 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:

 

 

rate structures;

 

 

rates of return on equity;

 

 

recovery of costs;

 

 

the services that our regulated assets are permitted to perform;

 

 

the acquisition, construction and disposition of assets; and

 

 

to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, 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. Natural gas companies may not charge rates that have not been determined to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

On September 29, 2006, Transwestern filed revised tariff sheets under section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. On March 9, 2007, Transwestern filed with the FERC its Stipulation and Agreement of Settlement (“Stipulation and Agreement”) which provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities. On April 27, 2007, the FERC approved the Stipulation and Agreement with an effective date of April 1, 2007. Transwestern’s tariff rates and fuel charges are now final until October 2011, the time stipulated in the settlement for the commencement of a new rate case.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its

 

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approach of pro-competitive policies 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. Any successful complaint or protest against Transwestern’s FERC-approved rates could have a prospective impact on our revenues associated with providing transmission services on Transwestern’s pipelines.

Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies.

Intrastate Pipeline Regulation. Our intrastate natural gas pipeline gathering and operations generally are not subject to rate regulation by FERC under the NGA; however, FERC’s regulation influences certain aspects of our business and the market for our products. In addition, our intrastate natural gas pipeline operations 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. The rates, terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline and ET Fuel System are subject to FERC regulation pursuant to Section 311 of the NGPA. 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. Should FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. 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.

In addition, our intrastate natural gas pipeline operations in Texas are subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. 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.

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.

 

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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, 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.

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.

Retail Propane Segment

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.

Competition

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.

Products, Services and Marketing

We distribute propane through a nationwide retail distribution network consisting of approximately 440 customer service locations in approximately 40 states, concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States.

Typically, customer service locations are found in suburban and rural areas where natural gas is not readily available. Such locations generally 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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Of the retail gallons we sold, approximately 57% were to residential customers, 30% were to industrial, commercial and agricultural customers, and 13% were to other retail users. Sales to residential customers in the fiscal year ended August 31, 2007 accounted for 57% of total retail gallons sold but accounted for approximately 69% 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 23% of our gross profit from propane sales for the fiscal year ended August 31, 2007, with all other retail users accounting for 8%. No single customer accounts for 10% or more of consolidated revenues.

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, 2007, Targa Liquids (“Targa”) and Enterprise Products Operating L.P. (“Enterprise”) provided approximately 23.0%, and 22.0% of our combined total propane supply, respectively. Enterprise is a subsidiary of Enterprise GP Holdings, L.P. (“Enterprise GP”), an entity that owns approximately 17.6% of the outstanding ETE Common Units and a 34.9% non-controlling equity interest in the LE GP and is therefore considered to be an affiliate of us. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. Additionally, HOLP has a monthly storage contract with TEPPCO Partners, L.P. (an affiliate of Enterprise).

In addition, M-P Energy Partnership (“M-P Energy”), a Canadian partnership in which our wholly-owned subsidiary, M.P. Oils, Ltd. (“MP Oils”), owned through August 31, 2007 a 60% interest, procured 20.7% of our combined total propane supply during the fiscal year ended August 31, 2007. M-P Energy buys and sells propane for its own account and supplies propane to us for our northern United States operations. ETP sold its interest in MP Oils in October 2007. We have executed a seven-year propane purchase agreement in connection with the sale of MP Oils (see Note 9 to our consolidated financial statements).

We believe that if supplies from Targa or Enterprise were interrupted we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Aside from Targa, Enterprise, and the supply procured by M-P Energy, no single supplier provided more than 10% of our total domestic propane supply during the fiscal year ended August 31, 2007. Although we cannot assure you that supplies of propane will be readily available in the future, 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. 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 and the new agreement with MP Oils, 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. 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. We receive our supply of propane predominately through railroad tank cars and common carrier transport.

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.

 

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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.

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;

 

 

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

 

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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, 2007 an accrual of $13.5 million was recorded in our consolidated balance sheet to cover estimated environmental liabilities including certain matters assumed in connection with our acquisition of the HPL System. 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.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean up activities include remediation of several compressor sites on the Transwestern system for presence of polychlorinated biphenyls (“PCBs”) which are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue for several years is approximately $12.3 million. Transwestern received FERC approval for rate recovery of the portion of soil and groundwater remediation not related to PCBs effective April 1, 2007.

Transwestern continues to incur certain costs related to PCBs that could migrate into customers’ facilities. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities totaled approximately $0.4 million for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at August 31, 2007. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

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. Environmental regulations were recently modified for United States Environmental Protection Agency’s Spill Prevention, Control and Countermeasures (“SPCC”) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

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

 

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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. We currently comply with the terms of this permit and associated regulations requiring specified reductions in nitrogen oxides or “NOx” emissions. During 2006 and 2007 we spent an estimated $3.0 million to modify the compressor engines at the facility. In addition, we have established 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. The NOx baseline has been established and we have 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. 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 pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a 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”. 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. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with these federal regulations and analogous state pipeline integrity requirements for our existing transportation assets other than Transwestern pipeline will result in capital costs of $7.9 million during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $13.1 million during that period. During this same time period, we estimate that we will incur pipeline integrity operating and on-going annual maintenance capital costs of $18.7 million with respect to our Transwestern pipeline. Through August 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us 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.

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 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 7, 2007, we employed 976 people to operate our natural gas operation segments. We employ 4,340 full-time employees to operate our propane segments. Of the propane employees, 64 are represented by labor unions. 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

 

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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 through ETP’s transportation pipelines and gathering systems;

 

 

the level of throughput in its processing and treating operations;

 

 

the fees it charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;

 

 

the price of natural gas;

 

 

the relationship between natural gas and NGL prices;

 

 

the weather in its 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 midstream companies, interstate pipeline companies, propane companies and other energy providers;

 

 

the level of its operating costs;

 

 

prevailing economic conditions; and

 

 

the level of ETP’s hedging activities.

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 level of costs related to litigation and regulatory compliance matters;

 

 

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;

 

 

its ability to access capital markets;

 

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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. ETP may not be able to 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.

The general partner is not elected by the Unitholders and cannot be removed without its consent.

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 (including Enterprise GP Holdings L.P.) own approximately 125.3 million Common Units, representing 56.22% of our outstanding Common 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.

 

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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, 2007, we had approximately $5.2 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;

 

 

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, 2007, 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, 2007, we had approximately $5.2 billion of consolidated debt, of which approximately $2.7 billion was at

 

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fixed interest rates and approximately $2.5 billion was at variable interest rates. We have entered interest rate swaps for a total notional amount of $1.6 billion, resulting in a net amount of $0.9 billion of variable-rate debt at August 31, 2007. 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:

 

 

our Unitholders’ current proportionate ownership interest in us will decrease;

 

 

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

 

 

the ratio of taxable income to distributions may increase;

 

 

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.

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.

 

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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 Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Mackie McCrea, President of Midstream Operations, and R. C. Mills, President of Propane Operations. Mr. Warren has been integral to the success of ETP’s midstream and transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing his 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 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 in which we do business. In some of the jurisdictions in which we do business, the applicable statutes do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner if:

 

 

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

 

your right to act with other Unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.

 

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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 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 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 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 and its affiliates).

If ETP GP 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 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 in ETP for fair market value, then the general partner interests and incentive distribution rights held by ETP GP 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 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 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.

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, 2007, we owned approximately 62.5 million 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.

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.

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

At August 31, 2007, our consolidated balance sheet reflected $748.0 million of goodwill and $211.7 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.

 

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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.

The risk of competition with affiliates of our General Partner has increased.

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. On May 7, 2007, Enterprise GP Holdings L.P. acquired a 34.9% non-controlling equity interest in our General Partner. Enterprise GP Holdings L.P. and its subsidiaries are a North American midstream energy business. As a result, there is greater risk that competition with affiliates of our General Partner could occur, which could adversely impact our results of operations and cash available for distribution.

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.

 

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Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.

 

 

Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our General Partner’s fiduciary duties to us and our Unitholders and restricts the remedies available to our Unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

 

permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

 

 

provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;

 

 

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

 

 

provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

In order to become a limited partner of our partnership, our Unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

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. As of August 31, 2007, affiliates of our General Partner excluding Enterprise GP Holdings, L.P. own approximately 38.7% of our Common Units.

We own an interstate pipeline that is subject to rate regulation by the Federal Energy Regulatory Commission and, in the event that 15% or more of our outstanding Common 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.

We own an interstate pipeline that is subject to rate regulation of the Federal Energy Regulatory Commission, or FERC, and as a result our General Partner has 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 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.

 

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ETP may issue additional ETP units, which may increase the risk that ETP will not have sufficient Available Cash to maintain or increase its per unit distribution level.

ETP has wide latitude to issue additional units on terms and conditions established by its General Partner. The payment of distributions on those additional units may increase the risk that ETP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our Unitholders.

The issuance of additional Common Units or other equity securities of equal rank will have the following effects:

 

 

our Unitholders’ proportionate ownership interest in ETP will decrease;

 

 

the amount of cash available for distribution on each Common Unit may decrease; and

 

 

the market price of our Common Units may decline.

Furthermore, our partnership agreement does not give our Unitholders the right to approve our issuance of equity securities.

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 intrastate transportation and storage operations are, 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 and intrastate transportation and storage operations are exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the North Texas System, Southeast Texas System and at ETP’s HPL 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 or gas daily average. 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 and processed at the North Texas System and Southeast Texas System, ETP enters into percentage-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements 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. Under processing fee agreements, we process the gas for a fee. If recoveries are less than those guaranteed the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole with regard to contractual recoveries.

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, 2007, the NYMEX settlement price for the prompt month contract ranged from a high of $8.87 per MMBtu to a low of $4.20 per MMBtu. A composite of the Mt. Belvieu

 

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average NGLs price based upon ETP’s average NGLs composition during ETP’s fiscal year ended August 31, 2007 ranged from a high of approximately $1.15 per gallon to a low of approximately $0.83 per gallon. 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.

ETP’s Oasis pipeline, East Texas pipeline, ET Fuel System and HPL System receive fees for transporting natural gas for its customers. Although a significant amount of the pipeline capacity of the East Texas pipeline and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of ETP’s transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels. 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 derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions, 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.

 

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Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity and production generally decrease as oil and natural gas prices decrease. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, ETP has no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

A substantial portion of ETP’s assets, including its gathering systems and its processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. 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.

Transwestern derives a significant portion of its revenue from charges to its customers for reservation of capacity, which charges Transwestern receives regardless of whether these customers actually use the reserved capacity. Transwestern also generates revenue from transportation of natural gas for customers without reserved capacity. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in demand for natural gas transportation on the Transwestern system over the long run. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.

The volumes of natural gas ETP transports on its intrastate transportation 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.

 

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If ETP does not make acquisitions on economically acceptable terms, its future growth could be limited.

ETP’s results of operations and its ability to grow and to increase distributions to Unitholders will depend in part on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit.

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 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.

If ETP does not continue to construct new pipelines, its future growth could be limited.

During the past several years, ETP has constructed several new pipelines, and ETP is currently involved in constructing several new pipelines. ETP’s results of operations and its ability to grow and to increase distributable cash flow per unit will depend, in part, on its ability to construct pipelines that are accretive to ETP’s distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

 

 

ETP is unable to identify pipeline construction opportunities with favorable projected financial returns;

 

 

ETP is unable to raise financing for its identified pipeline construction opportunities; or

 

 

ETP is unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or results from those projected prior to commencement of construction and other factors.

 

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Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks.

One of the ways that ETP has grown 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 or contracted capacity reservation commitments 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 and the demand for pipeline transportation 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 depends on certain key producers for its supply of natural gas on the Southeast Texas System and North Texas System, and the loss of any of these key producers could adversely affect its financial results.

For ETP’s fiscal year ended August 31, 2007, ConocoPhillips Company, Enervest Operating, L.L.C, Encana Oil and Gas (USA) Inc., and Lear Energy, LP supplied ETP with approximately 90% of the Southeast Texas System’s natural gas supply. For ETP’s fiscal year ended August 31, 2007, Encana Oil and Gas (USA), Inc., EOG Resources, Inc., XTO Energy Inc., and Chesapeake Energy Marketing, Inc. supplied ETP with approximately 80% of the North 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, ET Fuel System and HPL System.

ETP has 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 also has 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 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.

ETP completed its Cleburne to Carthage pipeline in April 2007. The major shippers through the Cleburne to Carthage pipeline expansion to interstate and intrastate markets are XTO Energy, Inc., EOG Resources, Inc., Chesapeake Energy Marketing, Inc., Encana Marketing (USA), Inc., Quicksilver Resources, Inc., and Leor Energy, L.P. These shippers have long-term contracts ranging from five to 10 years. The failure of these shippers to fulfill their contractual obligations 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.

ETP’s midstream and intrastate transportation and storage operations are generally exempt from Federal Energy Regulatory Commission, or (“FERC”), regulation under the NGA, but FERC regulation still significantly affects ETP’s business and the market for its products. The rates, terms and conditions of some of the transportation and storage services ETP provides on the HPL System, 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

 

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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. Should FERC determine not to authorize rates equal to or greater than our currently approved rates, we may suffer a loss of revenue. 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, New Mexico, Arizona, Louisiana, Utah and Colorado the states in which ETP operates these types of pipelines. ETP’s intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for 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 midstream gathering, processing and intrastate transportation operations are also subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado. 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 natural gas storage facilities of the ET Fuel System and the HPL System 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. Texas laws and 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.

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.

The FERC and CFTC are pursuing legal actions against ETP relating to certain natural gas trading and transportation activities, and related third party claims have been filed against us and ETP.

On July 26, 2007, the Federal Energy Regulatory Commission (the “FERC”) issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other dates from December 2003 though August 2005, in order to benefit financially from ETP’s

 

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commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the Natural Gas Act (“NGA”). ETP allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by the McGraw – Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha Hub in west Texas on certain dates in December 2005. The FERC’s action against ETP also includes allegations related to ETP’s Oasis pipeline, an intrastate pipeline that transports natural gas between the Waha Hub and the Katy Hub near Houston, Texas. The Oasis pipeline also transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority, and subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity is expected to account for approximately 1.0% of ETP’s operating income for its 2007 fiscal year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers (such as utilities and other end-users) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at prices that would be subject to FERC approval. Also on July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that ETP violated provisions of the Commodity Exchange Act by attempting to manipulate natural gas prices in the Houston Ship Channel. It is alleged that such manipulation was attempted during the period from late September through early December 2005 to allow ETP to benefit financially from ETP’s commodities derivatives positions.

In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC ordered ETP to show cause why the allegations against ETP made in the Order and Notice are not true. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. The FERC has taken the position that, once it receives ETP’s response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. In its lawsuit, the CFTC is seeking civil penalties of $130,000 per violation, or three times the profit gained from each violation, and other ancillary relief. The CFTC has not specified the number of alleged violations or the amount of alleged profit related to the matters specified in its complaint. On October 15, 2007, ETP filed a motion to dismiss in the United State District Court for the Northern District of Texas on the basis that the CFTC has not stated a valid cause of action under the Commodity Exchange Act.

It is ETP’s position that its trading and transportation activities during the periods at issue complied in all material respects with applicable laws and regulations, and ETP intends to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.

In addition to the FERC and CFTC legal actions, it is also possible that third parties will assert claims against ETP and ETE for damages related to these matters, which parties could include natural gas producers, royalty owners, taxing authorities, and parties to physical natural gas contracts and financial derivatives based on the Platts Inside FERC Houston Ship Channel index during the periods in question. In this regard, two natural gas producers have initiated legal proceedings against ETP and ETE for claims related to the FERC and CFTC claims. One of the producers has brought suit in Texas state court against ETP and ETE based on contractual and tort claims relating to alleged manipulation of natural gas prices at the Waha Hub in West Texas and the Houston Ship Channel and is seeking unspecified direct, indirect, consequential and punitive damages. The second producer has brought suit in Texas state court against ETP and ETE based on contract and tort claims relating to a natural gas purchase contract to which ETP and this producer are parties. This producer seeks unspecified damages and requests pre-arbitration discovery of information related to ETP’s activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. The producer also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5.9 million, plus interest and costs. In addition, a plaintiff has filed a putative class action against ETP in the United States District Court for the Southern District of Texas. This suit alleges that ETP unlawfully

 

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manipulated the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act, that ETP has the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, Waha, and Permian hubs, in order to benefit ETP’s natural gas physical and financial trading positions. The suit alleges that this unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels between December 29, 2003 and December 31, 2005, causing unspecified damages to plaintiff and all others who purchased and/or sold natural gas futures and options contracts on NYMEX during that period.

We are expensing the legal fees, consultants’ fees and related expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obligated to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obligated to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

Transwestern is subject to laws, regulations and policies governing the rates that it is allowed to charge for its services.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect Transwestern’s ability to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. Natural gas companies must charge rates that are deemed to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to the Natural Gas Act, existing rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. Further, other than for rates set under market-based rate authority, rates must be cost-based and the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level. Transwestern filed a general rate case in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file new cost-based rates until October 2011. In addition, shippers (other than shippers who have agreed not to challenge our tariff rates through 2010 pursuant to our recent settlement agreement with these shippers) may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services on a prospective basis. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future refinement or change.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates of an interstate petroleum products pipeline, Santa Fe Pacific Pipeline, or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification to those rates. The Court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its Unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest

 

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has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, the FERC issued its first case-specific oil pipeline review of the income tax allowance issues in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income allowance. Further, in the December 2005 order, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through entities pay the maximum marginal tax rate of 35% and that non-corporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the new income tax allowance policy were appealed to the D.C. Circuit. In May 2007, the D.C. Circuit affirmed FERC’s favorable income tax allowance policy. As a result, we remain eligible to include an allowance in the tariff rates we charge for natural gas transportation on our Transwestern interstate pipeline system, subject to our ability to demonstrate compliance with FERC’s policy. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. As FERC has recently approved ETP’s tariff rates specified in a settlement agreement with shippers, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is not subject to challenge prior to the expiration of ETP’s settlement agreement in 2011.

Transwestern is subject to laws, regulations and policies governing terms and conditions of service, which control many aspects of its business.

In addition to rate oversight, FERC’s regulatory authority extends to many other aspects of Transwestern’s business and operations, including:

 

 

operating terms and conditions of service;

 

 

the types of services Transwestern may offer to its customers;

 

 

construction of new facilities;

 

 

acquisition, extension or abandonment of services or facilities;

 

 

reporting and information posting requirements;

 

 

accounts and records; and

 

 

relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair Transwestern’s ability to compete for business or increase the cost and burden of operation.

Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1.0 million per day for each violation.

Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.

ETP’s business involves hazardous substances and may be adversely affected by environmental regulation.

ETP’s natural gas, as well as its propane operations 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 or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

 

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ETP may incur substantial environmental costs and liabilities because the underlying 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. The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations is approximately $12.3 million, which activities are expected to continue for several years.

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. For instance, the Texas Commission on Environmental Quality, or TCEQ, recently adopted a rule further restricting the level of nitrogen oxides, or NOx, that may be emitted from stationary gas-fired reciprocating internal combustion engines located in counties comprising the Dallas-Fort Worth eight hour ozone non-attainment area. As a result of the adoption of this rule, by March 1, 2009, ETP must either modify or replace seven owned and 21 leased compressor units currently located in the Dallas-Fort Worth non-attainment area that do not satisfy the TCEQ’s new, more stringent NOx emission limitations. ETP is evaluating its options to comply with this rule and thus the costs to comply currently are not reasonably estimable but such costs ultimately could be material to the operations of ETP. Also, the U.S. Congress is actively considering legislation and more than a dozen states have already taken legal measures to reduce emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere. Moreover, the U.S. Supreme Court recently decided, in Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.

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, North Texas System and HPL System and natural gas transportation customers for its transportation pipeline systems. 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 DCP Midstream, LLC. The North Texas System competes with Crosstex North Texas Gathering, LP and Devon Gas Services, LP for gathering and processing. The East Texas pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale region in north Texas. The ET Fuel System and the Oasis pipeline compete with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub. The ET Fuel System 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.

 

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The acquisitions of the HPL System and the Transwestern pipeline 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 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.

The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by our pipelines.

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.

The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American Tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

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 to us.

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 to us.

 

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ETP may be unable to bypass the processing plants, which could expose it to the risk of unfavorable processing margins.

Because of ETP’s ownership of the Oasis pipeline and ET Fuel System, it can generally elect to bypass the processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the Oasis pipeline and ET Fuel System. 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 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.

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, 2007, approximately 22.4% 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.

ETP’s operations are subject to regulation by the U.S. Department of Transportation, or DOT, under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a 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.” Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements for its existing transportation assets other than the Transwestern pipeline will result in capital costs of $7.9 million during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $13.1 million during that period. During this same time period, ETP estimates that it will incur pipeline integrity operating and on-going annual maintenance capital costs of $18.7 million with respect to its Transwestern pipeline. Through August 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through August 31, 2007, a total of $13.4 million of capital costs and $11.8 million of operating and maintenance costs have been incurred for pipeline integrity testing for transportation assets other than Transwestern. Through August 31, 2007, a total of $2.9 million of capital costs and $0.1 million of operating and maintenance costs have been incurred for pipeline integrity testing for Transwestern. 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.

 

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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.

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 ETE 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.

 

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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.

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 2007, ETP purchased approximately 23% and 22% of our propane from Targa Liquids and Enterprise, respectively. In addition, we purchased approximately 21% of our propane from M-P Energy Partnership, a Canadian partnership in which we owned through August 31, 2007 a 60% interest. Enterprise is a subsidiary of Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding Common Units and a 34.9% non-controlling interest in the General Partner of ETE, and is therefore considered to be an affiliate of us. 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.

 

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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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us or ETP as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of 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.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, 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 a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return 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 and other reasons, 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 our Unitholders would be reduced.

The tax treatment of our structure is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The U.S. federal income tax treatment of Unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. You should be aware that the U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS, and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our Common Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units.

 

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

If the IRS contests the federal income tax positions we or ETP takes, the market for our Common Units or ETP Common Units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our Unitholders.

The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we or ETP take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we or ETP take. A court may not agree with some or all of our counsel’s conclusions or 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 us or ETP, and therefore indirectly by us, as a Unitholder and as the owner of the general partner of ETP, reducing the cash available for distribution to 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.

Because our Unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if they receive no 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.

Tax gain or loss on disposition of our Common Units could be more or less than expected.

If Unitholders sell their Common Units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those Common Units. Because distributions in excess of the Unitholder’s allocable share of our net taxable income decrease the Unitholder’s tax basis in their Common Units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the Unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells units, the Unitholders may incur a tax liability in excess of the amount of cash received 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 effective tax 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.

 

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We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.

To maintain the uniformity of the economic and tax characteristics of our Common Units, we have adopted certain depreciation and amortization positions that are inconsistent with existing Treasury Regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our Unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not give any subsequent holder of a unit any such amortization deduction. This approach understates deductions available to those Unitholders who own those units and may result in those Unitholders believing that they have a higher tax basis in their units than is actually the case. This, in turn, may result in those Unitholders reporting less gain or more loss on a sale of their units than is actually the case.

The IRS may challenge the manner in which we calculate our Unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a Unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all Unitholders selling units within the period under audit as if all Unitholders owned such units.

Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our Unitholders.

A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our Unitholders. It also could affect the gain from a 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 our Unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to you.

ETP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public Unitholders of ETP. The IRS may challenge this treatment, which could adversely affect the value of ETP’s Common Units and our Common Units.

When we or ETP issue additional units or engage in certain other transactions, ETP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s Unitholders and us. Although ETP may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its Common Units as a means to measure the fair market value of its assets. ETP’s methodology may be viewed as understating the value of ETP’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP Unitholders and us, which may be unfavorable to such ETP Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ETP’s tangible assets and a lesser portion allocated to ETP’s intangible assets. The IRS may challenge ETP’s valuation methods, or our or ETP’s allocation of Section 743(b) adjustment attributable to ETP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’s Unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders or the ETP Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders or ETP’s Unitholders and could have a negative impact on the value of our Common Units or those of ETP or result in audit adjustments to the tax returns of our or ETP’s Unitholders without the benefit of additional deductions.

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.

Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a twelve month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units

 

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by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior twelve month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.

Based on the information currently available to us, we believe and intend to take the position that the sale of our Common Units by Ray C. Davis and Natural Gas Partners VI, L.P. to Enterprise GP Holdings, L.P. on May 7, 2007, together with all other Common Units sold within the prior twelve months, represented a sale or exchange of 50% or more of the total interest in our capital and profits interests and resulted in our termination and immediate reconstitution as a new partnership for federal income tax purposes. Moreover, our termination resulted in a deemed transfer of all of our interests in ETP, causing a termination of ETP’s partnership for federal income tax purposes. These terminations do not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. The closing of our taxable years will result in us and ETP both filing two tax returns (and Unitholders receiving two Schedule K-1’s) for one fiscal year. Moreover, these terminations will require both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP will be required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP (including Heritage Holdings as the holder of our Class E units) and, consequently, to our Unitholders. However, elections ETP and ETE will make with respect to the amortization of certain intangible assets should have the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.

We believe that the net effect of our tax termination and the tax termination of ETP will be an allocation for the 2007 calendar year of (i) an increased amount of taxable income as a percentage of the cash distributed to our Unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our Unitholders who purchased their units on or after the date of our initial public offering in February 2006. We estimate, based on our current distribution levels and various assumptions regarding the gross income and capital expenditures of ETP, that a Unitholder who purchased our units on the date of our initial public offering or a new purchaser of our units would be allocated taxable income of less than 10% of the cash distributed to them for the 2008 calendar year. In the case of a Unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our income or loss being includable in their taxable income for the year of termination.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our Common 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Substantially all of our pipelines, which are located in Arizona, New Mexico, Colorado, Utah, 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 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.

 

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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 one office building for our executive office 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, Florence, Kentucky, Tulsa, Oklahoma, and Denver, Colorado. 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 approximately 440 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 31 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, 2007, we utilized approximately 60 transport truck tractors, 60 transport trailers, 20 railroad tank cars, 1,700 bobtails and 2,700 other delivery and service vehicles, all of which we own. As of August 31, 2007, we owned approximately 1,130,000 customer storage tanks with typical capacities of 120 to 1,000 gallons that are leased or available for lease to customers. These customer storage tanks are pledged as collateral to secure 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.

ITEM 3. LEGAL PROCEEDINGS

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 they are subject.

 

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FERC/CFTC and Related Matters. On July 26, 2007, the Federal Energy Regulatory Commission (the “FERC”) issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other dates from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the Natural Gas Act (“NGA”). ETP allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha Hub and the Katy Hub near Houston, Texas. ETP’s Oasis pipeline transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority and is subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity is expected to account for approximately 1.0% of ETP’s operating income for its 2007 fiscal year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers (such as utilities and other end users) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at prices that would be subject to the FERC approval. Also on July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that ETP violated provisions of the Commodity Exchange Act by attempting to manipulate natural gas prices in the Houston Ship Channel. It is alleged that such manipulation was attempted during the period from late September through early December 2005 to allow ETP to benefit financially from ETP’s commodities derivatives positions.

In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. The FERC has taken the position that, once it receives ETP’s response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. In its lawsuit, the CFTC is seeking civil penalties of $130,000 per violation, or three times the profit gained from each violation, and other ancillary relief. The CFTC has not specified the number of alleged violations or the amount of alleged profit related to the matters specified in its complaint. On October 15, 2007, ETP filed a motion to dismiss in the United State District Court for the Northern District of Texas on the basis that the CFTC has not stated a valid cause of action under the Commodity Exchange Act.

It is ETP’s position that its trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and ETP intends to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.

In addition to the FERC and CFTC legal actions, it is also possible that third parties will assert claims against ETP for damages related to these matters, which parties could include natural gas producers, royalty owners, taxing authorities, and parties to physical natural gas contracts and financial derivatives based on the Platts Inside FERC Houston Ship Channel index during the periods in question. In this regard, two natural gas producers have initiated legal proceedings against ETP, one of which is seeking an unspecified amount of direct, indirect, consequential and punitive damages for alleged manipulation of natural gas prices at the Waha Hub in West Texas and the other is seeking to obtain discovery of information related to ETP’s activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. In addition, a plaintiff has filed a putative class action which purports to be brought on behalf of natural gas traders who purchased and/or sold natural gas futures and options on the New York Stock Mercantile Exchange between December 29, 2003 and December 31, 2005.

 

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We are expensing the legal fees, consultants’ fees and related expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

In re Natural Gas Royalties Qui Tam Litigation. MDL Docket No. 1293 (D. WY), Jack Grynberg, an individual, has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against Transwestern. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariffs, which were filed with and approved by the FERC. As a result, Transwestern believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Transwestern complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal which may be taken from the dismissal of the Grynberg case. Transwestern does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows. A hearing was held on April 24, 2007 regarding Transwestern’s Supplemental Brief for Attorneys’ fees which was filed on January 8, 2007 and the issues are submitted and are awaiting a decision. Grynberg moved to have the cases he appealed remanded to the district court for consideration in light of a recently-issued Supreme Court case. The defendants/appellees opposed the motion. The Tenth Circuit motions panel referred the remand motion to the merits panel to be carried with the appeals. Grynberg’s opening brief was due July 31, 2007. Appellees’ opposition brief is due November 21, 2007.

Transwestern Trespass Actions. Transwestern is managing one threatened trespass action related to right of way (“ROW”) on Tribal or allottee land. The threatened action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo that expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the United States Department of the Interior, Bureau of Indian Affairs (“BIA”) on behalf of the two allottees asserting trespass. Transwestern’s legal exposure related to this matter is not currently determinable. Negotiations are ongoing on this matter.

Another action involves an agreement with the BIA covering 44 miles of ROW on a total of 68 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee sent a letter dated January 16, 2004 to the BIA claiming Transwestern trespassed and that allotee’s claim of trespass has been settled and his consent to use the property has been acquired. Transwestern filed a renewal application with the BIA during October 2002, and has received two grants from the BIA for allotted lands in New Mexico and Arizona, which are effective through December 31, 2023.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies, and American Electric Power Corporation (“AEP”), were engaged in ongoing litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). 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

 

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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.

Other Matters. In addition to those matters described above, 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, for each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

As of August 31, 2007 and 2006, an accrual of $30.3 million and $32.1 million, 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 during the quarter ended August 31, 2007. See Note 7 to our consolidated financial statements.

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

The Parent Company’s Common Units are 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 (“IPO”) in February 2006.

 

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     Price Range   

Cash

Distribution(1)

     High    Low   

Fiscal Year 2007

        

Fourth Quarter Ended August 31, 2007

   $ 42.95    $ 29.82    $ 0.3900

Third Quarter Ended May 31, 2007

   $ 41.06    $ 33.20    $ 0.3725

Second Quarter Ended February 28, 2007

   $ 33.70    $ 28.80    $ 0.3560

First Quarter Ended November 30, 2006

   $ 29.99    $ 26.04    $ 0.3400
     Price Range   

Cash

Distribution(1)

     High    Low   

Fiscal Year 2006

        

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 relate. 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 price range 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 September 1, 2007, there were approximately 23,581 individual Common Unitholders, which includes Common Units held in street name. Common 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, 2007, we had 222,828,332 Common Units outstanding, of which 97,551,017 were held by the public; 95,695,303 were held by affiliates and 29,582,012 were held by our officers and directors. As of such date, the Common Units represent an aggregate 99.69% limited partner interest in us. Our General Partner owns an aggregate .31% General Partner 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.”

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.

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.

 

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The total amount of distributions declared by the Parent Company (all from Available Cash) during the years ended August 31, 2007 and 2006 is as follows:

 

     2007    2006

Limited Partners -

     

Limited Partners (a)

   $ —      $ 34,010

Common Units

     246,136      65,905

Class B Units

     1,645      745

Class C Units

     28,261      —  

General Partner

     955      599
             
   $ 276,997    $ 101,259
             

(a) Distributions to Limited Partners represent distributions to the 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

None during the quarter ended August 31, 2007. See Note 7 to our consolidated financial statements.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

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

In January 2004, we combined the natural gas midstream and transportation operations of ETC OLP with the retail propane operations of Heritage Propane Partners, L.P. (“Heritage”)(the “Energy Transfer Transactions”). In March 2004, Heritage changed its name to Energy Transfer Partners, L.P. Although Heritage 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 eleven months ended August 31, 2003 and the year ended August 31, 2004 below have been restated to report the results of the Elk City System as discontinued operations.

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.

 

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     Year Ended August 31,    

Eleven Months

Ended
August 31,

2003 (a)

 
Statement of Operations Data:    2007     2006     2005     2004    

Revenues:

          

Midstream segment

   $ 2,853,496     $ 4,223,544     $ 3,246,772     $ 1,880,663     $ 899,086  

Intrastate transportation and storage segment

     3,915,932       5,013,224       2,608,108       113,938       41,500  

Interstate transportation segment

     178,663       —         —         —         —    

Eliminations

     (1,562,199 )     (2,359,256 )     (471,255 )     (27,798 )     (9,559 )

Retail propane segment

     1,284,867       879,556       709,473       349,344       —    

Other

     121,278       102,028       75,700       30,810       —    
                                        

Total revenues

     6,792,037       7,859,096       6,168,798       2,346,957       931,027  

Gross margin

     1,713,831       1,290,780       787,283       365,533       105,589  

Depreciation and amortization

     191,383       129,636       105,751       56,242       11,870  

Operating income

     809,336       575,540       297,921       130,806       55,501  

Interest expense

     279,986       150,646       101,061       41,217       12,453  

Gain on Energy Transfer Transactions

     —         —         —         395,253       —    

Income from continuing operations before income tax expense and minority interest

     563,359       433,907       201,795       484,715       44,673  

Income tax expense (b)

     11,391       23,015       4,397       2,792       4,432  

Minority interests in income from continuing operations

     (232,608 )     (303,752 )     (96,946 )     (35,164 )     —    

Income from continuing operations

     319,360       107,140       100,452       446,759       40,241  

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

     1.56       0.80       0.89       4.54       0.47  

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

     1.55       0.79       0.75       3.35       0.30  

Cash distribution per unit

     1.46       2.56       2.66       1.36       0.03  

Balance Sheet Data (at period end):

          

Current assets

     1,050,578       1,302,736       1,453,730       481,868       223,897  

Total assets

     8,183,089       5,924,141       4,905,672       2,865,191       604,140  

Current liabilities

     932,815       1,020,787       1,244,785       404,917       169,967  

Long-term debt (less current maturities)

     5,198,676       3,205,646       2,275,965       1,071,158       196,000  

Partners’ capital (deficit)/Stockholders’ equity

     (47,132 )     45,751       (88,137 )     368,325       182,631  

Other Financial Data:

          

Cash flow provided by operating activities

     754,497       310,782       38,133       122,098       70,675  

Cash flow used in investing activities

     (2,158,090 )     (1,244,406 )     (1,131,117 )     (731,831 )     (341,258 )

Cash flow provided by financing activities

     1,454,739       926,369       1,043,591       637,513       325,655  

Capital expenditures:

          

Maintenance

     89,226       51,826       41,054       22,514       7,691  

Growth

     998,075       677,861       155,405       87,174       4,223  

Acquisition

     90,695       586,185       1,131,844       622,929       340,187  

(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 such 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, Heritage Service Corporation, and Titan Propane Services, Inc. are corporations subject to income taxes.
(c) See Note 4 to our consolidated financial statements for a discussion of the computation of earnings per unit.

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

AND RESULTS OF OPERATIONS

ETE was formed in September 2002 and completed its IPO of 24,150,000 Common Units in February 2006.

 

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The following is a discussion of our historical consolidated 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 of this report. 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.

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

Currently, the Parent Company’s business operations are conducted only through ETP’s Operating Partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas, and ETC Midcontinent Express Pipeline, LLC (“ETC MEP” or “MEP”), a Delaware limited liability company engaged in interstate transportation of natural gas, and HOLP and Titan, both Delaware limited partnerships engaged in retail propane operations.

Parent Company – Energy Transfer Equity, L.P.

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.

The Parent Company’s long-term debt increased significantly during the year ended August 31, 2007 as a result of debt incurred to finance the acquisition of Class G limited partner units of ETP (subsequently converted to Common Units). The purchase of Class G Units increased the Parent Company’s ownership of ETP limited partner interests from approximately 33% to approximately 46%.

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 current 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 completion of the Energy Transfer Transactions, which was the combination of the retail propane operations of Heritage and the midstream and intrastate transportation and storage operations of ETC OLP in January 2004. Subsequent to the combination we have made numerous significant acquisitions in both our natural gas and propane operations, most notably the following:

 

 

ET Fuel System in June 2004

 

 

HPL System in January 2005

 

 

Titan Propane in June 2006

 

 

Transwestern in December 2006

 

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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.

Our principal operations are conducted in the following significant segments:

 

 

Midstream

 

 

Intrastate transportation and storage

 

 

Interstate transportation

 

 

Retail propane

Summary of Operating Financial Performance in fiscal 2007

The fiscal 2007 year proved to be a challenging year for us. However, despite delays in certain of our major projects and the milder summer months in 2007, particularly in the southern portion of the United States, our management team and assets delivered another strong earnings performance for the year ended August 31, 2007 with $1.7 billion in gross margin and $809.3 million in operating income. In addition to the increased income generated from the Transwestern and Titan acquisitions, we also experienced increased volumes in our natural gas operations and better than expected processing margins throughout the fiscal year. We were also able to withdraw more working natural gas inventories from our Bammel storage facility resulting in increased margins, principally during the three months ended August 31, 2007.

ETP’s Operations

Our midstream and propane operations are primarily margin-driven businesses, while our transportation and storage operations are primarily fee-driven businesses. Thus, our results are significantly impacted by the margins we realize and the volumes we sell, transport and store, and to a lesser extent, commodity prices. Our fiscal year 2007 results were significantly impacted by our Transwestern acquisition in December 2006 and our Titan acquisition in fiscal year 2006.

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 acquisitions during fiscal year 2007 and the Titan and other acquisitions during fiscal year 2006 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 2007 and 2006, our other propane segment revenues, such as appliance sales, labor and tank rentals, also improved over prior years.

We also completed several growth capital projects during the fiscal year ended August 31, 2007 including the Cleburne to Carthage pipeline that extends from Cleburne, Texas to the Carthage Hub in East Texas and the Godley plant. In addition to our internal growth projects we also continued to integrate the Titan operations that were acquired in June 2006 and successfully completed the acquisition of the Transwestern pipeline in a two-step process in December 2006. The Transwestern pipeline is the first FERC-regulated pipeline for the Partnership.

In addition, we continued to secure long-term financing for ETP. ETP successfully raised $800 million in long-term debt with interest rates ranging from 6.125% to 6.625% and maturities ranging from 10 to 30 years. ETP also received proceeds of $1.2 billion from the sale of our Common Units during the year ended August 31, 2007. These proceeds were used principally to finance the Transwestern acquisition and to repay indebtedness incurred with the Titan acquisition which closed in June 2006. We also increased our borrowing capacity on our revolving credit facility in June 2007 from $1.5 billion to $2.0 billion (with an option to increase to $3.0 billion). The increased capacity will provide us with the liquidity needed to complete our previously announced expansion projects.

Trends and Outlook

Looking to fiscal 2008, we believe our operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion activity completed during fiscal year 2007, additional capacity resulting from pipeline projects expected to be completed within the next twelve to eighteen months (see Item 1 above), and incremental earnings related to the recently acquired Transwestern pipeline. In addition, we recently acquired the Canyon Gathering System in the Uinta-Piceance basins of Utah and Colorado which will provide for continued expansion into natural gas producing regions of the United States.

 

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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 in Item 8 of this Form 10-K.

The comparability of our consolidated financial statements is affected by the Parent Company’s purchase of Common Units and Class F Units (subsequently converted to Common Units) of ETP in February 2006, the Parent Company’s purchase of Class G Units of ETP in November 2006 (subsequently converted to Common Units), the Parent Company’s purchase of the remaining incentive distribution rights (“IDRs”) of ETP from Energy Transfer Investments, L.P. (“ETI”) in November 2006, ETP’s 100% acquisition of Transwestern on December 1, 2006 (and the acquisition of 50% of CCEH in November 2006), the acquisition of Titan in June 2006 and the HPL System in January 2005 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 2007, 2006 and 2005. The comparability is also affected by fluctuation in natural gas prices, mainly in our producer services’ gas sales and purchases and natural gas sales and purchases on our HPL System. Since we buy and sell natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our gas sales and purchases tend to be higher when natural gas prices are high and our gas sales and purchases tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues, trading activities, and basis differences between market hubs.

The acquisition of Transwestern resulted in a significant increase in our property, plant and equipment, intangible assets and goodwill from August 31, 2006 to August 31, 2007 (see Note 2 to the consolidated financial statements). The increase from August 31, 2006 to August 31, 2007 in our long-term debt was due to debt issued in connection with and debt assumed in the Transwestern acquisition, approximately $1.0 billion in growth capital expenditures incurred during fiscal year 2007, and borrowings to finance the Parent Company’s purchase of Class G Units from ETP.

Analysis of Operating Data – Volumes

Midstream

 

     Years Ended August 31,
     2007    2006    2005

Natural gas MMBtu/d

   941,140    1,552,753    1,578,833

NGLs Bbls/d

   25,657    10,425    12,707

 

 

For the year ended August 31, 2007, the decrease in natural gas volumes sold was principally due to less favorable market conditions during fiscal 2007 and increased utilization of capacity on our transportation pipelines by third parties resulting in lower sales volumes conducted by our producer services’ operations. The increase in NGL sales volumes was principally due to the completion of our Godley plant during 2007 and favorable market conditions to process and extract NGLs during fiscal 2007 compared to the same period last year.

 

 

For the year ended August 31, 2006, natural gas sales volumes decreased compared to the year ended August 31, 2005 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.

 

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Intrastate Transportation and Storage

 

     Years Ended August 31,
     2007    2006    2005

Natural gas MMBtu/d - transported

   6,124,423    4,633,069    3,495,434

Natural gas MMBtu/d - sold

   1,400,753    1,580,638    1,361,729

 

 

For the year ended August 31, 2007, transported natural gas volumes increased due to our continued efforts to secure more long-term shipper contracts, the completion of the Cleburne to Carthage pipeline, and increased demand to transport gas out of the Barnett Shale and Bossier Sands producing regions. Natural gas sales volumes on the HPL System for the year ended August 31, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials and due to the new CenterPoint contract that commenced on April 1, 2007. Under the previous contract, we sold and delivered natural gas to CenterPoint for a bundled price. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas capacity in our Bammel storage facility. As such, we now account for these activities as natural gas transported rather than natural gas sold.

 

 

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, ET Fuel System and East Texas pipeline 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.

Interstate Transportation

 

     Years Ended August 31,
     2007    2006    2005

Natural gas MMBtu/d - transported

   1,802,109    —      —  

Natural gas MMBtu/d - sold

   19,680    —      —  

 

 

The increase was due to the 100% acquisition of Transwestern on December 1, 2006.

Retail Propane

 

     Years Ended August 31,
     2007    2006    2005

Retail propane gallons sold (in thousands)

   604,269    429,118    406,334

 

 

The retail propane operations realized significant increases in gallons sold in the year ended August 31, 2007 as compared to the year ended August 31, 2006 (a 175.2 million net gallon increase) primarily due to the Titan acquisition in June 2006. The combination of below normal degree days, customer conservation, and the slow down of new home construction in our propane markets has contributed to a decrease in expected volumes sold and slowed internal growth. The overall weather in our areas of operations during the year ended August 31, 2007 was 10.6% warmer than the year ended August 31, 2006 and 7.2% warmer than normal.

 

 

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, 2007 was 3.5% warmer than the year ended August 31, 2005 and 10.6% warmer than normal.

 

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Analysis of Results of Operations

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

Comparison of Fiscal Years Ending August 31, 2007, 2006 and 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:

 

     Years Ended August 31,    Amount of Change  
     2007     2006     2005    2007-2006     2006-2005  

Equity in earnings of affiliates

   $ 435,247     $ 204,987     $ 141,260    $ 230,260     $ 63,727  

General and administrative expense

     8,496       55,374       1,051      (46,878 )     54,323  

Interest expense

     104,405       36,773       9,529      67,632       27,244  

Loss on extinguishment of debt

     —         5,060       —        (5,060 )     5,060  

Interest and other income (expense), net

     (2,356 )     (638 )     16,066      (1,718 )     (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 increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 is directly related to the increased ownership in ETP as a result of the Common, Class F and Class G Unit acquisitions in February 2006 and November 2006 and the increased ownership of ETP IDRs, as discussed above, and the changes in the ETP segment income described below.

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 increased ownership of ETP as a result of the Common and Class F Unit acquisitions in February 2006 and the changes in the ETP segment income described below.

The change in the Parent Company’s ownership share of ETP during fiscal years 2007, 2006 and 2005 was as follows:

 

     Limited
Partner
Interest
    IDRs     General
Partner
Interest
 

Interests prior to December 2005

   31 %   100 %   2 %

December 2005 distribution to ETI

   —       (50 )%   —    

Purchase of ETP Common and Class F Units in February 2006

   2 %   —       —    

Purchase of ETP Class G Units in November 2006

   13 %   —       —    

Purchase of IDRs from ETI in November 2006

   —       50 %   —    
                  

Interests as of August 31, 2007

   46 %   100 %   2 %
                  

General and Administrative Expenses. The decrease in general and administrative expenses of the Parent Company for the year ended August 31, 2007 compared to the year ended August 31, 2006 and the increase in general and administrative expenses 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 fiscal year 2006 in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO. (See Note 7 to our consolidated financial statements).

 

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Interest Expense. The Parent Company interest expense increased for the year ended August 31, 2007 compared to 2006 primarily due to the increased borrowings to fund the acquisition of Class G units from ETP in November 2006. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” and Note 6 to our consolidated financial statements below for more information on the Parent Company’s indebtedness.

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.

Loss on Extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs during fiscal year 2006 in connection with the repayment of the $600.0 million senior secured term loan agreement as described above. There was no similar repayment during fiscal year 2007 or 2005.

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,     Amount of Change  
     2007     2006     2005     2007-2006     2006-2005  

Consolidated Information:

          

Revenues

   $ 6,792,037     $ 7,859,096     $ 6,168,798     $ (1,067,059 )   $ 1,690,298  

Cost of sales

     5,078,206       6,568,316       5,381,515       (1,490,110 )     1,186,801  
                                        

Gross margin

     1,713,831       1,290,780       787,283       423,051       503,497  

Operating expenses

     559,600       422,989       319,554       136,611       103,435  

Selling, general and administrative

     153,512       162,615       64,057       (9,103 )     98,558  

Depreciation and amortization

     191,383       129,636       105,751       61,747       23,885  
                                        

Operating income

     809,336       575,540       297,921       233,796       277,619  

Interest expense

     (279,986 )     (150,646 )     (101,061 )     (129,340 )     (49,585 )

Loss on extinguishment of debt

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

Equity in earnings (losses) of affiliates

     5,161       (479 )     (376 )     5,640       (103 )

Gain (loss) on disposal of assets

     (6,310 )     851       (330 )     (7,161 )     1,181  

Interest and other income, net

     35,158       13,701       12,191       21,457       1,510  

Income tax expense

     (11,391 )     (23,015 )     (4,397 )     11,624       (18,618 )

Minority interests

     (232,608 )     (303,752 )     (96,946 )     71,144       (206,806 )
                                        

Income from continuing operations

   $ 319,360     $ 107,140     $ 100,452     $ 212,220     $ 6,688  

Income from discontinued operations, net of income tax expense

     —         —         46,294       —         (46,294 )
                                        

Net income

   $ 319,360     $ 107,140     $ 146,746     $ 212,220     $ (39,606 )
                                        

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

Interest Expense. For the year ended August 31, 2007 compared to the year ended August 31, 2006, interest expense increased $129.3 million. The principal factor for this increase is a net $67.6 million increase in interest expense related to borrowings of the Parent Company, a net $51.2 million increase in interest expense related to borrowings on the Partnership’s 2006 and 2005 Senior Notes and the revolving credit facility. Borrowings increased primarily due to the financing of our growth capital expenditures and the CCEH/Transwestern and Titan acquisitions. Debt assumed in the Transwestern acquisition resulted in $12.5 million of increased interest expense. During the year ended August 31, 2006 losses of $0.1 million on interest rate swaps were recorded as an increase to interest expense. Such activity was not recognized in interest expense in the year ended August 31, 2007; rather, such activity was included in interest and other income. Hedge ineffectiveness charges increased interest expense by $1.8 million in fiscal 2007, compared to gains of $0.8 million in fiscal 2006. See Note 11—“Price Risk Management Assets and Liabilities”, included in our consolidated financial statements for further discussion on interest rate hedges. Propane related interest decreased $5.1 million due primarily to the scheduled debt payments that have occurred between fiscal periods 2006 and 2007.

 

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Index to Financial Statements

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 System acquisition, offset principally by an increase in unrealized gains and the ineffective charges 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 wrote off $6.6 million of debt issuance costs associated with the ETP debt that was repaid with the proceeds from the issuance of $750.0 million of 5.95% senior notes.

Equity in Earnings of Affiliates. The increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 was due primarily to $5.1 million of equity income from our 50% ownership of CCEH for the month of November 2006. We did not have an investment in CCEH in fiscal 2006. We redeemed our investment in CCEH in connection with our Transwestern acquisition on December 1, 2006.

Gain (Loss) on Disposal of Assets. The loss on disposal of assets reflected in the year ended August 31, 2007 was principally due to losses resulting from the sale of a compressor station.

Interest and Other Income, Net. The increase in interest and other income for the year ended August 31, 2007 compared to the year ended August 31, 2006 is due primarily to gains on interest rate swaps that are not accounted for as cash flow hedges. Such gains were included in interest expense in fiscal 2006. Other income in fiscal year 2006 includes $7.7 million received from the favorable judgment on the SCANA litigation (see Notes 7 and 10 of our consolidated financial statements for further detail).

The increase in interest and other income for the year ended August 31, 2006 compared to the year ended August 31, 2005 is primarily due to $7.7 million received from the favorable judgment on the SCANA litigation (see Notes 7 and 10 of our consolidated financial statements for further detail).

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 decreased expense for the year ended August 31, 2007 was attributed principally to higher income from trading gains recognized by a taxable subsidiary during the year ended August 31, 2006, than was realized by such subsidiary in the current fiscal year. The decrease was partially offset by the Texas margin tax that was not effective until January 1, 2007.

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 decrease in minority interest expense in fiscal year 2007 is attributable to the Parent Company’s acquisition of ETP limited partner interests in November 2006 (discussed above), offset by 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.

The increase in minority interest expense in fiscal year 2006 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 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.

 

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Index to Financial Statements

There were no discontinued operations for the years ended August 31, 2006 or 2007.

Segment Operating Results

We evaluate segment performance based on operating income (either in total or by individual segment) which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

We do not include earnings from equity method unconsolidated affiliates in our measurement of operating income because such earnings have not been significant historically.

For additional information regarding our business segments, see Item 1 and Notes 1 and 14 to our Consolidated Financial Statements included under Item 8 of this annual report.

Operating income by segment is as follows:

 

     Years Ended August 31,     Amount of Change  
     2007     2006     2005     2007-2006     2006-2005  

Midstream

   $ 119,233     $ 147,564     $ 94,603     $ (28,331 )   $ 52,961  

Intrastate Transportation and Storage

     479,820       422,420       151,819       57,400       270,601  

Interstate Transportation

     95,650       —         —         95,650       —    

Retail Propane

     124,263       76,055       66,902       48,208       9,153  

Other

     1,735       1,899       (683 )     (164 )     2,582  

Unallocated selling, general and administrative expenses

     (11,365 )     (72,398 )     (14,720 )     61,033       (57,678 )
                                        

Operating income

   $ 809,336     $ 575,540     $ 297,921     $ 233,796     $ 277,619  
                                        

We do not believe the Other operating income is material for further disclosure and/or discussion.

Unallocated Selling, General and Administrative Expenses. Prior to December 2006, the selling, general and administrative expenses that relate to the general operations of the Partnership were not allocated to our segments. In conjunction with the Transwestern acquisition, selling, general and administrative expenses are now allocated to the Operating Partnerships. For the year ended August 31, 2007, a net $18.4 million was allocated to the Operating Partnerships, which constituted the decrease in total unallocated selling general and administrative expenses from the year ended August 31, 2006. The decrease in the unallocated selling, general and administrative expenses due to the allocations now in place to the Operating Partnerships, is offset by increases in expenses primarily related to management incentive plans.

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 million recorded in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO (see Note 7 to our consolidated financial statements), 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.

 

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Midstream

 

     Years Ended August 31,    Amount of Change
     2007    2006    2005    2007-2006     2006-2005

Revenues

   $ 2,853,496    $ 4,223,544    $ 3,246,772    $ (1,370,048 )   $ 976,772

Cost of sales

     2,632,187      4,000,461      3,102,539      (1,368,274 )     897,922
                                   

Gross margin

     221,309      223,083      144,233      (1,774 )     78,850

Operating expenses

     39,148      31,910      22,835      7,238       9,075

Selling, general and administrative

     35,597      23,922      9,685      11,675       14,237

Depreciation and amortization

     27,331      19,687      17,110      7,644       2,577
                                   

Segment operating income

   $ 119,233    $ 147,564    $ 94,603    $ (28,331 )   $ 52,961
                                   

Gross Margin. For the year ended August 31, 2007, midstream’s gross margin decreased by $1.8 million primarily due to the net effect of the following factors:

 

 

Decrease in net trading revenues of $17.9 million. During the fiscal 2006 period, we recognized trading gains resulting principally from commodities futures positions that benefited from market anomalies following the hurricanes that struck the Texas and Louisiana coasts in August and September 2005. Trading activities during the year ended August 31, 2007 resulted in a net gain of $2.2 million;

 

 

Decrease in non-trading margin from our marketing activities of $36.0 million. Market conditions, including lower basis differentials between the west and east Texas markets and increased third-party utilization of our transportation pipeline capacity, resulted in lower sales volumes conducted by our producer services’ operations; and

 

 

Increase in processing margin and fee-based revenue. The increase was due to the completion of our Godley plant in the first quarter of 2007, the acquisition of three gathering systems during fiscal 2007, and favorable processing conditions during fiscal 2007 compared to the same period last year at our Southeast Texas System.

For the year ended August 31, 2006, midstream’s gross margin increased by $78.9 million primarily due to the following factors:

 

 

Trading gains recognized during the 2006 fiscal year resulting from commodities futures positions that benefited from market anomalies following the hurricanes that struck the Texas and Louisiana coasts in August and September 2005; and

 

 

Increased processing margins on our Southeast Texas System as a result of favorable processing conditions during the year ended August 31, 2006 compared to the year ended August 31, 2005.

Operating Expenses. Midstream operating expenses increased $7.2 million for the year ended August 31, 2007 compared to the year ended August 31, 2006. The increase was primarily driven by increased compressor rental expense of $3.7 million, increased compressor maintenance of $1.0 million, increased electricity costs of $0.9 million, and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $1.8 million. The increases were primarily driven by the Godley plant addition and the acquisition of three gathering systems during the first six months of fiscal 2007. The increases were offset by reduced measurement expense of $1.6 million due to a larger portion being allocated to the transportation segment due to the continued expansion in that segment.

Midstream operating expenses increased $9.1 million between the years ended August 31, 2006 and 2005 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.

Selling, General and Administrative Expenses. Midstream general and administrative expenses for the year ended August 31, 2007 increased $11.7 million compared to the year ended August 31, 2006. The increase was attributable to $13.2 million of increased legal costs primarily associated with regulatory inquiries, a $4.1 million allocation of parent company administrative expenses for overhead costs which previously had not been allocated, and increases of $3.9 million in employee-related costs such as salaries, incentive compensation and healthcare costs. The increase was offset by increases of $7.9 million in departmental costs allocated to the intrastate transportation and storage operating segment and an increase of $2.4 million in overhead costs capitalized to capital expansion projects.

 

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Index to Financial Statements

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 intrastate 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. The increase of $7.6 million for the year ended August 31, 2007 compared to the year ended August 31, 2006 is principally due to plant and equipment placed into service during fiscal year 2007, the completion of our Godley plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

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

Intrastate Transportation and Storage

 

     Years Ended August 31,    Amount of Change
     2007    2006    2005    2007-2006     2006-2005

Revenues

   $ 3,915,932    $ 5,013,224    $ 2,608,108    $ (1,097,292 )   $ 2,405,116

Cost of sales

     3,137,712      4,322,217      2,280,082      (1,184,505 )     2,042,135
                                   

Gross margin

     778,220      691,007      328,026      87,213       362,981

Operating expenses

     181,133      171,312      113,166      9,821       58,146

Selling, general and administrative

     52,844      46,520      27,021      6,324       19,499

Depreciation and amortization

     64,423      50,755      36,020      13,668       14,735
                                   

Segment operating income

   $ 479,820    $ 422,420    $ 151,819    $ 57,400     $ 270,601
                                   

Gross Margin. For the year ended August 31, 2007 as compared to the year ended August 31, 2006, intrastate transportation and storage gross margin increased by $87.2 million, principally due to the net effect of the following:

 

 

Volumes. Overall volumes on our transportation pipelines were higher during fiscal 2007 compared to fiscal 2006 due to the completion of the Cleburne to Carthage pipeline, continued efforts to secure long-term shipper contracts, increased demand to transport natural gas from the Barnett Shale and Bossier Sands producing regions, and a colder winter in fiscal 2007. Transportation fees increased approximately $61.0 million for the year ended August 31, 2007 compared to the year ended August 31, 2006. Retention revenue increased approximately $35.1 million due to increased volumes transported on our pipelines;

 

 

Lower natural gas prices. 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. Our average natural gas prices for retained fuel decreased from a range of $5.00 to $12.00/MMBtu during the year ended August 31, 2006 to $4.00 to $7.00/MMBtu during the same period this year resulting in a decrease in revenue by $28.8 million;

 

 

Increase in storage margin of $26.0 million. The increase was due to approximately $40.0 million in margin recognized on 17.5 Bcf more volume withdrawn from our Bammel storage facility in fiscal 2007 than in fiscal 2006 and a significant loss on settled derivatives during fiscal 2006. These increases were offset by approximately $18.0 million in margin on gas sold from our Bammel storage facility and delivered to a customer in September 2005. There were no similar sales during the year ended August 31, 2007; and

 

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Decrease in margin of $28.7 million related to well head volumes. As discussed above, we purchase natural gas from producers at a discount to a specified price and resell to customers at an index price. We experienced lower volumes and lower natural gas prices during the year ended August 31, 2007 compared to the same period last year.

For the year ended August 31, 2006 as compared to fiscal year 2005, intrastate 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 also successfully secured more firm contracts as evidenced by our transportation agreement with XTO (see Note 10 to our consolidated financial statements). In addition, our Fort Worth Basin expansion, completed in May 2005, 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;

 

 

The acquisition of the HPL System in January 2005. The results for the year ended August 31, 2005 contain seven months of the HPL System’s operating results as compared to twelve months of the HPL System operating results included in fiscal year 2006. For the year ended August 31, 2006, the HPL System 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 hedging gains 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; and

 

 

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. Intrastate transportation and storage operating expenses increased $9.8 million when comparing the year ended August 31, 2007 to the year ended August 31, 2006. The increase was principally attributable to increases of $12.5 million in pipeline and compressor maintenance and compressor rentals, $3.6 million in property taxes, and $2.3 million in employee-related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a decrease of $11.0 million in fuel consumption which was due to higher natural gas prices in the early part of fiscal 2006.

For the year ended August 31, 2006 compared to fiscal year 2005, intrastate transportation and storage operating expenses increased $58.1 million. The increase was principally attributable to increases of $32.4 million in operating expenses related to the HPL System 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. Intrastate transportation and storage general and administrative expenses increased $6.3 million for the year ended August 31, 2007 compared to the year ended August 31, 2006 principally due

 

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to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects.

For the year ended August 31, 2006 compared to the year ended August 31, 2005, intrastate transportation and storage selling, general and administrative expenses increased $19.5 million 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 System acquisition and an increase in salaries and wages, incentive compensation expense, and other employee-related expenses.

Depreciation and amortization. Intrastate transportation and storage depreciation and amortization expense increased $13.7 million for the year ended August 31, 2007 compared to the year ended August 31, 2006, principally due to plant and equipment placed into service during fiscal year 2007.

For the year ended August 31, 2006 compared to the year ended August 31, 2005, intrastate transportation and storage depreciation and amortization expense increased $14.7 million, principally due to the HPL System acquisition in January 2005, the Fort Worth Basin Pipeline completed in May 2005 and additional compressors and equipment added to existing systems.

Interstate Transportation

 

     Years Ended August 31,   

Amount of

Change

     2007    2006   

Revenues

   $ 178,663    $ —      $ 178,663

Operating expenses

     36,295      —        36,295

Selling, general and administrative

     18,746      —        18,746

Depreciation and amortization

     27,972      —        27,972
                    

Segment operating income

   $ 95,650    $ —      $ 95,650
                    

The increase in all categories between fiscal years ending August 31, 2007 and 2006 was due to the acquisition of 100% of Transwestern on December 1, 2006.

No comparative data is presented for fiscal year 2005 as the Transwestern acquisition did not take place until fiscal year 2007.

Retail Propane

 

     Years Ended August 31,    Amount of Change
     2007    2006    2005    2007-2006    2006-2005

Retail propane revenues

   $ 1,179,073    $ 799,358    $ 641,071    $ 379,715    $ 158,287

Other retail propane related revenues

     105,794      80,198      68,402      25,596      11,796

Retail propane cost of sales

     734,204      493,642      384,186      240,562      109,456

Other retail propane related cost of sales

     25,430      21,776      19,554      3,654      2,222
                                  

Gross margin

     525,233      364,138      305,733      161,095      58,405

Operating expenses

     297,469      212,188      176,277      85,281      35,911

Selling, general and administrative

     32,668      17,859      11,067      14,809      6,792

Depreciation and amortization

     70,833      58,036      51,487      12,797      6,549
                                  

Segment operating income

   $ 124,263    $ 76,055    $ 66,902    $ 48,208    $ 9,153
                                  

Revenues. Retail propane revenue increased $379.7 million between the years ended August 31, 2007 and 2006, mainly due to the increase in volumes sold by customer service locations added through the Titan acquisition in June 2006. The increase in retail propane revenues was offset somewhat by weather that was 7.2% warmer than normal weather and 10.6% warmer than last year. Other retail propane related revenues increased $25.6 million for the year ended August 31, 2007 compared to fiscal year 2006 primarily due to other propane related revenues of companies we have acquired between the two years and enhanced fee generating programs in servicing our customers.

 

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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, 2007 compared to the year ended August 31, 2006, retail propane cost of sales increased by $240.6 million which mainly relates to the increase in gallons sold by customer service locations added through the Titan acquisition.

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, 2007 compared to fiscal year 2006 is primarily related to the Titan acquisition in June 2006. The propane margin remained strong during the fiscal year ended August 31, 2007 during the periods of warmer weather and higher fuel prices. Optimization of the margins is influenced by market opportunities, independent competitors and concerns for long term retention of customers.

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.

Operating Expenses. During the year ended August 31, 2007, operating expenses increased by $85.3 million compared to the same period last year. The increase is directly related to the operating expenses of the identifiable Titan operations. Included in these operating expenses are increases that relate to higher vehicle fuel costs and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan acquisition, and other acquisition costs related to blends and mergers of propane locations to gain forward synergies and cost savings.

During the year ended August 31, 2006, operating expenses increased by $35.9 million compared to fiscal 2005 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, 2007 and 2006 is primarily due to increases from administrative expense allocations, increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition. The increase also includes increases in our IT costs as we continue to enhance our current infrastructure for our administrative and propane systems. Effective with the Transwestern acquisition in December 2006, an allocation of administrative expenses is now made to the operating partnerships, which increased the retail propane selling, general and administrative expenses by a net $7.9 million for the year ended August 31, 2007.

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 Expense. The increase of $12.8 million in depreciation and amortization expense for the year ended August 31, 2007 as compared to 2006 is due primarily to the acquisition of Titan on June 1, 2006. Depreciation and amortization increased $6.5 million for the fiscal year ended August 31, 2006 as compared to August 31, 2005, primarily due to the depreciation and amortization of assets and amortizable intangibles added through acquisitions during fiscal 2006.

 

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Income Taxes

As a limited 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, 2007, 2006 and 2005, our non-qualifying income was not expected to, or did not, exceed the statutory limit.

Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a 12-month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.

Based on the information currently available to us, we believe that we exceeded the 50% threshold on May 7, 2007, and, as a result, we have determined that our partnership terminated for federal tax income purposes on that date. Our termination also caused ETP to terminate for federal income tax purposes on that date. These terminations do not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. These terminations will require both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP will be required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP and, consequently, to our Unitholders. However, elections ETP and ETE will make with respect to the amortization of certain intangible assets will have the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.

We believe that the net effect of our tax termination and the tax termination of ETP will be an allocation for the 2007 calendar year of (i) an increased amount of taxable income as a percentage of the cash distributed to our Unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our Unitholders who purchased their units on or after the date of our initial public offering in February 2006. We estimate, based on our current distribution levels and various assumptions regarding the gross income and capital expenditures of ETP, that a Unitholder who purchased our units on the date of our initial public offering or a new purchaser of our units would be allocated taxable income of less than 10% of the cash distributed to them for the 2008 calendar year. In the case of a Unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our income or loss being includable in their taxable income for the year of termination.

As a result of the tax termination discussed above, we elected new depreciation and amortization policies for income tax purposes, which include the amortization of goodwill. As a result of the income tax regulations related to remedial income allocations, ETP’s subsidiary, HHI, which owns ETP’s Class E units, receives a special allocation of taxable income, for income tax purposes only, essentially equal to the amount of goodwill amortization deductions allocated to purchasers of ETP common units. The amount of such “goodwill” accumulated as of the date of ETP’s acquisition of HHI (approximately $158 million) is now being amortized over 15 years beginning on May 7, 2007, the date of our new tax elections. ETP accounts for HHI using the treasury stock method due to its ownership of ETP’s Class E units. Due to the accounting rules outlined in SFAS 109 and related Interpretations, ETP accounts for the tax effects of the goodwill amortization and remedial income allocation as an adjustment of ETP’s HHI purchase price allocation, which effectively results in a charge to ETP’s common equity and a deferred tax benefit offsetting the current tax expense resulting from the remedial income allocation for tax purposes. For the year ended August 31, 2007, this resulted in a

 

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current tax expense and deferred tax benefit (with a corresponding charge to common equity as an adjustment of the purchase price allocation) of approximately $1.2 million. As of August 31, 2007, the amount of tax goodwill to be amortized over the next 15 years for which HHI will receive a remedial income allocation is approximately $155 million.

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

 

     Years Ended August 31,  
     2007     2006     2005  

Federal statutory tax rate

   35.00 %   35.00 %   35.00 %

State income tax rate net of federal benefit

   1.25 %   3.10 %   3.56 %

Earnings not subject to tax at the Partnership level

   (34.23 )%   (32.80 )%   (36.58 )%
                  

Effective tax rate

   2.02 %   5.30 %   1.98 %
                  

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

 

     Years Ended August 31,  
     2007     2006     2005  

Continuing operations -

      

Current provision:

      

Federal

   $ 7,896     $ 27,640     $ 5,042  

State

     10,432       1,987       963  
                        
     18,328       29,627       6,005  

Deferred provision (benefit):

      

Federal

     (7,494 )     (6,227 )     (2,015 )

State

     557       (385 )     407  
                        
     (6,937 )     (6,612 )     (1,608 )

Total tax provision on continuing operations

     11,391       23,015       4,397  

Discontinued operations -

      

Current income tax expense:

      

Federal

     —         —         1,570  

State

     —         —         259  
                        

Total Tax Provision

   $ 11,391     $ 23,015     $ 6,226  
                        

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the year ended August 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $6.9 million. There is no comparable state tax expense for the years ended August 31, 2006 or 2005.

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.

 

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The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited 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 $237.8 million. 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 was 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. The terms of the Class G Units were substantially similar to those of ETP’s Common Units, as discussed in Note 7 to our consolidated financial statements. On May 1, 2007, the ETP Class G Units converted to ETP Common Units upon approval of the ETP Common Unitholders.

In a separate but related transaction, on November 1, 2006, ETE acquired from ETI, the remaining 50% ownership of Class B limited partner interests in ETP GP, which have the right to distributions of general partner IDRs of ETP, resulting 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 the ETP GP Class B interests owned by ETI and the assumption of ETI debt of $70.5 million. See Note 2 of our condensed consolidated financial statements for discussion of the accounting for the transaction with ETI.

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. This facility was amended on December 4, 2006 to consolidate ETE’s existing term loan of $150 million with the new $1.3 billion term loan to form one facility totaling $1.45 billion with a maturity date of November 1, 2012. 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.

On November 28, 2006 the Parent Company sold 7,789,133 Common Units to a group of institutional investors in a private placement at a price of $27.41 per unit, resulting in net proceeds of approximately $213.5 million. The Parent Company used the proceeds to repay indebtedness under its credit facility.

On March 2, 2007 the Parent Company issued approximately 5.0 million Common Units in a private placement to a group of institutional investors. The units were issued at a price of $31.96 per unit resulting in approximately $160.0 million in net proceeds to the Parent Company. The proceeds were used to repay Parent Company indebtedness.

In connection with the November 2006 and March 2007 private placement of units, the Parent Company executed registration rights agreements under which it agreed to file a shelf registration statement under the Securities Act within 90 days of closing of the private placement. The Form S-3 shelf registration statement was filed on September 25, 2007, and provides for a primary offering of Common Units up to a total of $2.0 billion and a secondary offering of approximately 66.6 million Common Units by selling Unitholders.

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.

 

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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 we expect to expend approximately $70 million in the next fiscal year and capital expenditures to extend the useful lives of ETP’s propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet for which ETP expects to expend approximately $35 million in the next fiscal year;

 

 

growth capital expenditures, mainly for constructing new pipelines, processing plants, treating plants and compression for the midstream and intrastate transportation and storage segment for which we expect to expend approximately $1.0 billion in the next fiscal year. We also expect to spend approximately $800 million in our interstate segment for constructing new pipelines and pipeline expansion and approximately $30 million for customer propane tanks in the next fiscal year; and

 

 

acquisition capital expenditures including acquisition of new pipeline systems and propane operations. As a partnership practice, we do not budget for acquisitions.

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 may 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 may be financed by the proceeds of borrowings under the existing ETP credit facilities, long-term debt, the issuance of additional Common Units or a combination thereof; and

 

 

acquisition capital expenditures may 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 used in ETP’s natural gas operations, 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. 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 businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond its control. However, ETP includes these factors into its anticipated growth capital expenditures for each fiscal year.

ETP manages its exposure to increased pipe costs by purchasing steel and reserving mill space, as projects are approved, in advance of construction. However, there is no assurance that ETP will not be impacted by increased pipe costs and limited mill space.

In connection with the HPL System 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.

During fiscal year 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 Common Units. Through August 31, 2007, ETP has not made any sales under this Registration Statement.

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 Transwestern and Titan operations, and other factors.

 

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Operating Activities. Cash provided by operating activities during the year ended August 31, 2007, was $754.5 million as compared to cash provided by operating activities of $310.8 million for the year ended August 31, 2006. The net cash provided by operations for the year ended August 31, 2007 consisted of net income of $319.4 million, non-cash charges of $187.0 million, principally minority interests, non cash unit-based compensation expense and depreciation and amortization, and cash from changes in operating assets and liabilities of $248.1 million. Various components of operating assets and liabilities changed significantly from the prior period due to factors such as the change in value of price risk management assets and liabilities, 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 intrastate transportation and storage operations.

Investing Activities. Cash used in investing activities during the year ended August 31, 2007 of $2.2 billion is comprised primarily of cash paid for our investment in CCEH of $1.0 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $90.7 million and $1.0 billion invested for growth capital expenditures (including the payment of $9.4 million accrued in prior periods) of which $974.6 million related to natural gas operations and $32.9 million to propane operations. We also incurred $89.2 million in maintenance expenditures needed to sustain operations of which $63.2 million related to natural gas operations and $26.0 million to propane.

Financing Activities. Cash provided by financing activities was $1.5 billion for the year ended August 31, 2007. We received $372.4 million in proceeds from the sale of Common Units. We had a net increase of $1.4 billion in our debt level, of which $1.0 billion was used to fund the purchase of the member interests of CCEH and the remainder was used to repay the indebtedness we incurred in connection with the Titan acquisition as discussed in Note 2 to our consolidated financial statements. On October 23, 2006, we received net proceeds of $791.0 million from the issuance of senior notes (see Note 6 to our consolidated financial statements) which we used to repay borrowings under the Partnership’s revolving credit facility. In January and February 2007, we borrowed a total of approximately $307.0 million on our Revolving Credit Facility to fund required pre-payments of the debt we assumed in connection with our acquisition of Transwestern. In May 2007, Transwestern issued $307.0 million principal of Senior Unsecured Series Notes from which we used $295.0 million to repay borrowings and accrued interest outstanding under the Partnership’s revolving credit facility and $12.0 million for general partnership purposes. During the year ended August 31, 2007, we paid $23.3 million debt issue costs related to debt issuances. During the year ended August 31, 2007 we paid distributions of $277.0 million to our partners.

Financing and Sources of Liquidity

Description of Indebtedness

ETE’s consolidated indebtedness as of August 31, 2007 includes the Parent Company’s Senior Secured Credit Agreement which includes a $1.45 billion Senior Secured Term Loan Facility available through November 1, 2012 and a $500 million Senior Secured Revolving Credit Facility available through February 8, 2011. ETP has $750 million in principal amount of 5.95% Senior Notes due 2015, $400 million in principal amount of 5.65% Senior Notes due 2012, $400 million in principal amount of 6.125% Senior Notes due 2017 and $400 million in principal amount of 6.625% Senior Notes due 2036 (collectively, the “ETP Senior Notes”), a revolving credit facility that allows for borrowings of up to $2.0 billion (expandable to $3.0 billion) available through June 20, 2012 (the “ETP Credit Facility”), and a $310 million, 364-day term loan credit facility executed on October 5, 2007 (discussed below). ETP also assumed long-term debt in connection with the Transwestern acquisition which is discussed in detail below. We also currently maintain a separate credit facility for HOLP. The terms of our indebtedness and our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements. 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 subsidiaries’ ability to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of August 31, 2007, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.

Parent Company Indebtedness

On December 4, 2006, the Parent Company entered into a Second Amendment to Amended and Restated Credit Agreement, dated December 4, 2006 (as amended, the “Parent Company Credit Agreement”) with BNP, CitiCorp North American, JPMorgan Chase, UBS Securities and Wachovia Capital Markets, with Wachovia Bank, NA as

 

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Administrative Agent. The Parent Company Credit Agreement provided for the consolidation of the three separate outstanding Term Loans into a single $1.45 billion Term Loan Facility and a Term Loan Maturity Date of November 1, 2012. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance debt assumed in the transaction with ETI discussed above and for liquidity and general Partnership purposes.

The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. 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.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of August 31, 2007 was $1.6 billion with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company’s debt facilities as of August 31, 2007 was $378.5 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 facility’s capacity up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio which is currently at Level III or 0.375%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. At August 31, 2007, the weighted average interest rate was 7.1061% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1.45 billion Senior Secured Term Loan Facility.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries including its ownership of 62.5 million ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership in ETP GP. The financial covenants contained in the revolving credit facility include a leverage ratio test, a consolidated leverage ratio test, an 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.

ETP Indebtedness

ETP Senior Notes

On October 23, 2006, ETP closed the issuance, under a $1.5 billion S-3 Registration Statement, of $400.0 million of 6.125% senior notes due 2017 and $400.0 million of 6.625% senior notes due 2036. ETP used the net proceeds of approximately $791.0 million from the issuance of the notes to repay borrowings and accrued interest outstanding under its previously existing revolving credit facility, to pay expenses associated with the offering and for general partnership purposes. 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 ETP Senior Notes represent senior unsecured obligations and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. In connection with the Partnership entering into the credit agreement for the ETP Credit Facility in July 2007 as described in more detail below, all guarantees by ETC OLP, Titan and all of their direct and indirect wholly-owned subsidiaries for the ETP Senior Notes were released and discharged. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

The ETP 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 assets.

 

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Transwestern Assumed Long-Term Debt and Senior Unsecured Series Notes

On December 1, 2006 ETP assumed the following long-term debt in connection with the Transwestern acquisition:

 

5.39% Notes due November 17, 2014

   $ 270,000  

5.54% Notes due November 17, 2016

     250,000  
        

Total long-term debt outstanding

     520,000  

Unamortized debt discount

     (623 )
        

Total long-term debt assumed

   $ 519,377  
        

No principal payments are required under any of the Transwestern debt agreements prior to their respective maturity dates. Due to a change in control provision in Transwestern’s debt agreements, Transwestern was required to pre-pay $292 million and $15 million in February and March 2007, respectively. These payments were financed with borrowings from the ETP’s previously existing revolving credit facility.

In May 2007, Transwestern issued a total of $307 million aggregate principal amount of Senior Unsecured Series Notes (“Transwestern Series Notes”) comprised of the following:

 

Principal    Interest Rate    

Maturity Date

$ 82,000    5.64 %   May 24, 2017
  150,000    5.89 %   May 24, 2022
  75,000    6.16 %   May 24, 2037

The Partnership used $295 million of the proceeds received to repay borrowings and accrued interest outstanding under its then existing revolving credit facility and $12 million for general partnership purposes. Interest is payable semi-annually, and the Transwestern Series Notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern Series Notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.

Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.

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 HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of August 31, 2007 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Revolving Credit and Short-Term Debt Facilities

ETP Facilities

ETP Credit Facility. On July 20, 2007, we entered into the ETP Credit Facility with Wachovia Bank, National Association, as administrative agent and Bank of America, N.A., as syndication agent, and certain other agents and lenders. The ETP Credit Facility replaced our previously existing $1.5 billion revolving credit facility, and all outstanding borrowings and letters of credit

 

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under our previously existing credit facility were replaced by borrowings and letters of credit under the ETP Credit Facility. The $1.5 billion prior credit facility was then terminated. The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion at our option (subject to the approval of the administrative agent under the Amended and Restated Credit Agreement, which approval is not to be unreasonably withheld). The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments under the ETP Credit Facility). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.0 billion unless expanded to $3.0 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. The indebtedness under the ETP Credit Facility is prepayable at any time at the Partnership’s option without penalty. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.

The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries ability to, among other things:

 

 

incur indebtedness;

 

 

grant liens;

 

 

enter into mergers;

 

 

dispose of assets;

 

 

make certain investments;

 

 

make Distributions during certain Defaults and during any Event of Default;

 

 

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

 

 

engage in transactions with affiliates;

 

 

enter into restrictive agreements; and

 

 

enter into speculative hedging contracts.

This credit agreement also contains a financial covenant that provides that on each date the Partnership makes a Distribution, the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified Acquisition Period (as such terms are used in this credit agreement).

As of August 31, 2007, there was a balance of $969.4 million in revolving credit loans (including $107.4 million in Swingline loans) and $57.3 million in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2007, was 6.01%. The total amount available under the ETP Credit Facility, as of August 31, 2007, which is reduced by any amounts outstanding under the swingline loan and letters of credit, was $973.3 million. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries. In connection with entering into the credit agreement for the ETP Credit Facility, all guarantees by ETC OLP, Titan and their direct and indirect wholly-owned subsidiaries of the ETP Senior Notes were released and discharged. The indebtedness under the ETP Credit Facility has the same priority of payments as our other current and future unsecured debt.

ETP Term Loan. On October 5, 2007, ETP entered into a credit agreement providing for a $310 million, 364-day term loan credit facility (the “Term Loan Agreement”). Borrowings under the Term Loan Agreement were used to fund the purchase price for the Canyon acquisition and for general corporate purposes. The facility is a single draw term loan with an applicable Eurodollar rate plus 0.600% per annum based on our current rating by the rating agencies or at Base Rate for designated period. The indebtedness under the Term Loan Agreement is unsecured and is not guaranteed by any of our subsidiaries. Borrowings under the Term Loan Agreement, upon proper notice to the administrative agent, may be prepaid in whole or in part without premium or penalty. The Term Loan Agreement requires any proceeds received from debt or equity issuance, assets sales, or accordion increases be used to make a mandatory prepayment on the outstanding loan balance. The Term Loan Agreement contains covenants that are similar to the covenants of our existing ETP Credit Facility.

Prior ETP Credit Facilities. On September 25, 2006, ETP exercised the accordion feature of its previously existing revolving credit facility and expanded the amount of the facility from $1.3 billion to $1.5 billion. Amounts borrowed under ETP’s previously existing revolving credit facility bore interest at a rate based on either a Eurodollar rate or a prime rate. ETP’s previously existing revolving credit facility had 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 varied based on ETP’s credit rating and the maximum fee was 0.175%. ETP’s previously existing revolving credit facility was fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries of ETP. ETP’s previously existing revolving credit facility was unsecured and had equal rights to holders of ETP’s other current and future unsecured debt.

On October 18, 2006 ETP paid and retired a $250 million unsecured revolving credit facility which matured under its terms on December 1, 2006. Amounts borrowed under this facility bore interest at a rate based on either a Eurodollar

 

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rate or a base rate. The maximum commitment fee payable on the unused portion of the facility was 0.25%. The $250 million revolving credit facility was fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.

HOLP Facilities

Effective August 31, 2006, HOLP entered into the Fourth Amended and Restated Credit Agreement, a $75 million Senior Revolving Facility available through June 30, 2011 (the “HOLP Facility”) which may be expanded to $150 million. The HOLP Facility has a swingline loan option with a maximum borrowing of $10 million at a prime rate. Amounts borrowed under the HOLP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. 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 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 HOLP Facility (total book value as of August 31, 2007 of approximately $1.2 billion). There was no balance outstanding on the HOLP Facility as of August 31, 2007. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Facility. There were outstanding letters of credit under the HOLP Facility of $1.0 million at August 31, 2007. The sum of the loans made under the HOLP Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the maximum amount of the HOLP 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 us to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA, as defined in the agreements, for the specified four fiscal quarter period of not greater than 5.0 to 1.0, with a permitted increase to 5.5 to 1.0 during a specified Acquisition Period (these terms are defined in the credit agreement related to the ETP Credit Facility), Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) 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 these ratios, 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 divestitures 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 note agreements related to the HOLP Notes 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, 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, Transwestern’s and HOLP’s debt agreements as of August 31, 2007.

 

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Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of August 31, 2007:

 

     Payments Due by Period

Contractual Obligations

   Total    Less Than
1 Year
   1-3 Years    3-5 Years    More Than
5 Years

Long-term debt

   $ 5,245,739    $ 47,063    $ 85,955    $ 1,144,908    $ 3,967,813

Interest on fixed rate long-term debt (a)

     1,952,088      167,744      354,086      340,718      1,089,540

Payments on derivatives

     6,197      5,233      964      —        —  

Purchase commitments (b)

     717,350      607,854      109,496      —        —  

Operating lease obligations

     98,788      13,492      27,249      29,877      28,170
                                  

Totals

   $ 8,020,162    $ 841,386    $ 577,750    $ 1,515,503    $ 5,085,523
                                  

(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, 2007, variable rate interest on our outstanding balance of variable rate debt of $2.5 billion would be $180.6 million on an annual basis. See Note 6 – “Debt Obligations” to the consolidated financial statements 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 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, 2007 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.

In August 2007 and in connection with a reimbursable agreement entered into by MEP with a financial institution, ETP executed a percentage guaranty with the same financial institution whereby it would be liable for its 50% of any defaulted payments not made by MEP, plus interest. The reimbursable agreement has a commitment up to $197.0 million, as amended, and expires in September 2008.

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 2007

   July 2, 2007    July 19, 2007    $ 0.3725
   April 9, 2007    April 16, 2007      0.3560
   January 4, 2007    January 19, 2007      0.3400
   October 5, 2006    October 19, 2006      0.3125

Fiscal Year 2006

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

 

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On September 25, 2007, the Parent Company announced the declaration of a cash distribution for the fourth quarter ended August 31, 2007 of $0.39 per Common Unit, or $1.56 annually, an increase of $0.07 per Common Unit on an annualized basis. The distribution was paid on October 19, 2007 to Unitholders of record at the close of business on October 5, 2007.

The total amount of distributions (all from Available Cash from the Parent Company’s operating surplus) declared during the years ended August 31, 2007, 2006 and 2005 are as follows:

 

     2007    2006    2005

Limited Partners –

        

Limited Partners (a)

   $ —      $ 34,010    $ 666,751

Common Units

     246,136      65,905      —  

Class B Units

     1,645      745      —  

Class C Units

     28,261      —        —  

General Partner

     955      599      4,861
                    

Total distributions declared

   $ 276,997    $ 101,259    $ 671,612
                    

(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, 100% of ETP’s incentive distribution rights and ETP Common Units held by the Parent Company.

The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights for the years ended August 31, 2007, 2006 and 2005 is as follows:

 

     2007    2006     2005  

Limited Partners Interests

   $ 174,969    $ 80,203     $ 57,671  

General Partner Interest

     12,701      6,931       4,237  

Incentive Distribution Rights

     183,056      64,436       27,971  

Less holdback (a)

     —        (2,287 )     (8,182 )
                       

Total distributions received from ETP

   $ 370,726    $ 149,283     $ 81,697  
                       

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

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 (as defined in ETP’s partnership agreement) 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.

 

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Distributions declared by ETP during the years ended August 31, 2007, 2006 and 2005 are summarized as follows:

 

     Record Date   Payment Date    Amount per Unit

Fiscal Year 2007

   July 2, 2007   July 16, 2007    $ 0.80625
   April 6, 2007   April 13, 2007      0.78750
   January 4, 2007   January 15, 2007      0.76875
   October 5, 2006   October 16, 2006      0.75000

Fiscal Year 2006

   June 30, 2006   July 14, 2006    $ 0.63750
   June 30, 2006 (1)   July 14, 2006      0.03250
   March 24, 2006   April 14, 2006      0.58750
   January 4, 2006   January 13, 2006      0.55000
   September 30, 2005   October 14, 2005      0.50000

Fiscal Year 2005

   July 8, 2005   July 14, 2005    $ 0.48750
   March 16, 2005   April 14, 2005      0.46250
   January 5, 2005   January 14, 2005      0.43750
   October 7, 2004   October 15, 2004      0.41250

(1) Special SCANA distribution – On June 20, 2006, the Board of Directors of ETP’s 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. 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 distribution of $3.6 million to the holder of ETP’s Class C Units for that amount that would otherwise have been distributed to its General Partner.

On September 25, 2007, ETP announced the declaration of a cash distribution for the fourth quarter ended August 31, 2007 of $0.825 per Common Unit, or $3.30 annually, an increase of $0.075 per Common Unit on an annualized basis. The distribution was paid on October 16, 2007 to Unitholders of record at the close of business on October 5, 2007.

The total amount of distributions (all from Available Cash from ETP’s operating surplus) declared during the years ended August 31, 2007, 2006 and 2005 are as follows:

 

     2007    2006    2005

Limited Partners –

        

Common Units

   $ 366,180    $ 248,237    $ 173,802

Class C Units (1)

     —        3,599      —  

Class F Units

     —        3,232      —  

Class G Units

     40,598      —        —  

General Partners –

        

2% Ownership

     12,701      6,981      4,390

Incentive Distribution Rights

     203,069      81,722      28,847
                    
   $ 622,548    $ 343,771    $ 207,039
                    

(1) Special SCANA distribution – see discussion above.

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

 

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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 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 adopted this statement on September 1, 2007. We are continuing to evaluate the impact of FIN 48, but at this time we believe that the adoption of FIN 48 will not have a significant impact on our consolidated financial statements.

FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements (“FSP 00-19-2”). FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5, Accounting for Contingencies (“SFAS No. 5”). FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. We adopted this Staff Position on September 1, 2007 and the impact was not significant.

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 adopted the provisions of SFAS 154 on September 1, 2006, with no material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other 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. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. 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 calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).

SFAS Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), (“SFAS 158”). Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement

 

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are effective for fiscal years ending after December 15, 2008. Management does not believe the adoption of the measurement provisions of this statement will have a material impact on our financial statements. We plan to adopt the measurement provisions of this statement when required during our calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, (“SFAS 159”). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective, however, the amendment applies to all entities with available-for-sale and trading securities. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes the choice in the first 120 days of that fiscal year and also elects to apply the provisions of FASB Statement No. 157, Fair Value Measurements (discussed above). 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 calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).

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.

SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). In September 2006, the Securities and Exchange Commission (“SEC”) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB 108 on August 31, 2007. The adoption did not have a material impact on our consolidated financial statements.

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 to our consolidated financial statements.

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 accruals for 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. Variances in these estimates, including variances in volume estimates, are inherent in our business. Actual results could differ from our estimates if the underlying assumptions prove to be incorrect, and such differences could be material.

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.

 

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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 intrastate transportation and storage segment and interstate transportation 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 intrastate 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.

Transwestern is subject to FERC regulations. As a result, FERC may require the refund of revenues collected during the pendency of a rate proceeding in a final order. Transwestern establishes reserves for these potential refunds, as appropriate. No such reserves were required at August 31, 2007.

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.

Regulatory Assets and Liabilities. Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to Statement of Financial Accounting Standards No. 71 (As Amended), Accounting for the Effects of Certain Types of Regulation (“SFAS 71”), which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

 

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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 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. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for further discussion regarding our derivative activities.

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 and intangibles with infinite lives 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 3 to 80 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.

 

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Asset Retirement Obligation. An entity is required to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective. 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.

Legal Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints.

For more information on our litigation and contingencies, see Note 10 to our consolidated financial statements included in Item 8 in this report.

Forward-Looking Statements

This annual report contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

 

 

the amount of natural gas transported on ETP’s pipelines and gathering systems;

 

 

the level of throughput in ETP’s natural gas processing and treating facilities;

 

 

the fees ETP charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;

 

 

the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs;

 

 

energy prices generally;

 

 

the prices of natural gas and propane compared to the price of alternative and competing fuels;

 

 

the general level of petroleum product demand and the availability and price of propane supplies;

 

 

the level of domestic oil, propane and natural gas production;

 

 

the availability of imported oil and natural gas;

 

 

the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

 

 

actions taken by foreign oil and gas producing nations;

 

 

the political and economic stability of petroleum producing nations;

 

 

the effect of weather conditions on demand for oil, natural gas and propane;

 

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availability of local, intrastate and interstate transportation systems;

 

 

the continued ability to find and contract for new sources of natural gas supply;

 

 

availability and marketing of competitive fuels;

 

 

the impact of energy conservation efforts;

 

 

energy efficiencies and technological trends;

 

 

governmental regulation and taxation;

 

 

changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;

 

 

hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;

 

 

the maturity of the propane industry and competition from other propane distributors;

 

 

competition from other midstream companies, interstate pipeline companies and propane distribution companies;

 

 

loss of key personnel;

 

 

loss of key natural gas producers or the providers of fractionation services;

 

 

reductions in the capacity or allocations of third party pipelines that connect with ETP’s pipelines and facilities;

 

 

the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments;

 

 

the nonpayment or nonperformance by ETP’s customers;

 

 

regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

 

 

risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities;

 

 

the availability and cost of capital and ETP’s ability to access certain capital sources;

 

 

the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses;

 

 

changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

 

 

the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in Item 1A of this annual report.

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 and intrastate transportation and storage operations. 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 Chief Executive Officer, Chief Financial Officer, Chief Administrative and Compliance Officer, Treasurer, President—Midstream, Controller of our midstream and intrastate 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

 

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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. We do not engage in any derivative related activities in our interstate transportation segment.

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.

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 the HPL System, 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 intrastate 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 intrastate 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 assume limited market price risk. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain transactions and forward contracts are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis swaps and gas daily contracts. These instruments are within the guidelines of the risk management policy which has

 

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been approved by our Board of Directors. The trading activities are a complement 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.

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 intrastate 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.

Commodity-related Derivatives

Our commodity-related price risk management assets and liabilities as of August 31, 2007 were as follows:

 

     Commodity    Notional
Volume
MMBTU
    Maturity    Fair
Value
 

Mark to Market Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    14,195,262     2007-2009    $ 5,551  

Swing Swaps IFERC

   Gas    7,282,500     2007-2008      (514 )

Fixed Swaps/Futures

   Gas    (590,000 )   2007-2009      1,298  

Forward Physical Contracts

   Gas    (6,437,413 )   2007-2008      343  

Options

   Gas    (976,000 )   2007-2008      (346 )

Forward/Swaps—in Gallons

   Propane/Ethane    8,862,000     2007-2008      777  

(Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (4,922,500 )   2007-2008    $ 2,390  

Swing Swaps IFERC

   Gas    (21,250,000 )   2007      (33 )

Forward Physical Contracts

   Gas    —       2007      323  

Fixed Swaps/Futures

   Gas    (10,275,000 )   2007      (177 )

Cash Flow Hedging Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (10,962,500 )   2007-2008    $ 124  

Fixed Swaps/Futures

   Gas    (11,230,000 )   2007-2009      23,078  

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, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

 

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Sensitivity analysis

The table below summarizes our commodity-related financial derivative instruments and fair values as of August 31, 2007. It also 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

   (11,820,000 )   $ 24,376     $ 10,929

Basis Swaps IFERC/NYMEX

   3,232,762       5,675       1,091

Swing Swaps IFERC

   7,282,500       (514 )     467

Options

   (976,000 )     (346 )     190

Forward Physical Contracts’

   (6,437,413 )     343       3,442

Propane Forwards/Swaps (in Gallons)

   8,862,000       777       3,495

Trading Derivatives

      

Swing Swaps IFERC

   (21,250,000 )     (33 )     1,737

Basic Swaps IFERC/NYMEX

   (4,922,500 )     2,390       17

Forward Physical Contracts

   —         323       2,980

Fixed Swaps/Futures

   (10,275,000 )     (177 )     5,579

The table below summarizes our positions and values as of August 31, 2006. It also 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

Basic Swaps IFERC/NYMEX

   (2,572,500 )     21,995       701

Forward Physical Contracts

   (455,000 )     (68 )     75

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 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) and the relationship between prompt month and forward months.

Interest Rate Risk

We are exposed to market risk for changes in interest rates, primarily as a result of our variable rate debt and, in particular, our bank credit facilities. To the extent interest rates increase, our interest expense for our revolving credit facilities will also increase. At August 31, 2007, we had a total of $2.541 billion of variable rate debt outstanding and we have $1.625 billion of interest rate swaps where we pay fixed and receive floating LIBOR. Interest swaps with a notional amount of $700.0 million are designated as hedges and changes in fair value are recorded in accumulated other comprehensive income. Interest swaps with a notional amount of $925.0 million have their changes in fair value recorded in other income on the consolidated statement of operations. A hypothetical change of 100 basis points in the underlying interest rate and a corresponding parallel shift in the LIBOR yield curve would have an effect of $26.4 million in interest expense and other income, in the aggregate, on an annual basis.

 

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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. For further information, see Note 11 to our consolidated financial statements.

 

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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

   91

Consolidated Balance Sheets – August 31, 2007 and 2006

   92

Consolidated Statements of Operations – Years Ended August 31, 2007, 2006, and 2005

   94

Consolidated Statements of Comprehensive Income (Loss) – Years Ended August 31, 2007, 2006, and 2005

   95

Consolidated Statements of Partners’ Capital (Deficit) – Years Ended August 31, 2007, 2006, and 2005

   96

Consolidated Statements of Cash Flows – Years Ended August 31, 2007, 2006, and 2005

   97

Notes to Consolidated Financial Statements

   98

 

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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, 2007 and 2006, 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, 2007. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended August 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Energy Transfer Equity L.P.’s internal control over financial reporting as of August 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated October 29, 2007 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Dallas, Texas

October 29, 2007

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

 

     August 31,
2007
   August 31,
2006
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 77,350    $ 26,204

Marketable securities

     3,099      2,817

Accounts receivable, net of allowance for doubtful accounts

     637,676      675,545

Accounts receivable from related companies

     5,979      602

Inventories

     192,276      387,140

Deposits paid to vendors

     45,490      87,806

Exchanges receivable

     32,891      23,221

Price risk management assets

     10,363      56,851

Prepaid expenses and other

     45,454      42,549
             

Total current assets

     1,050,578      1,302,735

PROPERTY, PLANT AND EQUIPMENT, net

     5,971,127      3,748,614

LONG-TERM PRICE RISK MANAGEMENT ASSETS

     151      2,192

ADVANCES TO AND INVESTMENT IN AFFILIATES

     56,564      41,344

GOODWILL

     748,018      633,998

INTANGIBLES AND OTHER LONG-TERM ASSETS, net

     356,651      195,258
             

Total assets

   $ 8,183,089    $ 5,924,141
             

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,
2007
    August 31,
2006
 
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)     

CURRENT LIABILITIES:

    

Accounts payable

   $ 487,834     $ 603,527  

Accounts payable to related companies

     19,136       320  

Exchanges payable

     34,252       24,722  

Customer advances and deposits

     81,919       108,836  

Accrued wages and benefits

     53,504       40,247  

Accrued and other current liabilities

     199,653       164,898  

Price risk management liabilities

     2,707       36,918  

Income taxes payable

     6,486       83  

Deferred income taxes

     261       629  

Current maturities of long-term debt

     47,063       40,607  
                

Total current liabilities

     932,815       1,020,787  

LONG-TERM DEBT, less current maturities

     5,198,676       3,205,646  

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES

     3,685       2,843  

DEFERRED INCOME TAXES

     198,947       207,877  

OTHER NON-CURRENT LIABILITIES

     13,666       2,110  

MINORITY INTERESTS

     1,882,432       1,439,127  

COMMITMENTS AND CONTINGENCIES

    
                

Total liabilities

     8,230,221       5,878,390  
                

PARTNERS’ CAPITAL (DEFICIT):

    

General Partner

     24       (69 )

Limited Partners:

    

Common Unitholders (222,828,332 and 124,360,520 units authorized, issued and outstanding at August 31, 2007 and 2006, respectively)

     (58,918 )     (9,586 )

Class B Unitholders (0 and 2,521,570 units authorized, issued and outstanding) at August 31, 2007 and 2006, respectively)

     —         53,130  
                
     (58,894 )     43,475  

Accumulated other comprehensive income, per accompanying statements

     11,762       2,276  
                

Total partners’ capital (deficit)

     (47,132 )