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Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended August 31, 2006

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

For the Transition Period from to

Commission file number 001-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

Delaware

30-0108820

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

2828 Woodside Street, Dallas, Texas 75204

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

Title of class

Name of each exchange on

which registered

Common Units

New York Stock Exchange

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

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

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

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

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non accelerated filer x

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

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

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


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

Documents Incorporated by Reference: None

ENERGY TRANSFER EQUITY, L.P.

2006 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS


		PAGE
	PART I

ITEM 1.	BUSINESS	1

ITEM 1A.	RISK FACTORS	20

ITEM 1B.	UNRESOLVED STAFF COMMENTS	41

ITEM 2.	PROPERTIES	41

ITEM 3.	LEGAL PROCEEDINGS	43

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	43

	PART II

ITEM 5.	MARKET FOR THE REGISTRANT’S COMMON UNITS AND RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	44

ITEM 6.	SELECTED FINANCIAL DATA	45

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	47

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	78

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	82

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	142

ITEM 9A.	CONTROLS AND PROCEDURES	143

ITEM 9B.	OTHER INFORMATION	143

	PART III

ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	143

ITEM 11.	EXECUTIVE COMPENSATION	147

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	150

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	152

ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	154

	PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	155

PART I

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by us in periodic press releases and some oral statements of our officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect”, “continue,” “estimate,” “goal,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we and our General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, neither we or our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. When considering forward-looking statements, please read the section titled “Risk Factors” included under Item 1A of this annual report.

ITEM 1. BUSINESS

Overview

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

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

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

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

ETP’s Operations

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

natural gas currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. Our transportation and storage segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through our Oasis Pipeline, our East Texas Pipeline, our Fort Worth Basin Pipeline, our natural gas pipeline and storage assets that are referred to as the ET Fuel System, and our Houston Pipeline System, which are described below.

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

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

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


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

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P. (“Heritage”) and the Parent Company completed a series of transactions whereby the Parent Company contributed its subsidiary, ETC OLP, to Heritage in exchange for cash of $300.0 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed-upon capital expenditures paid by the Parent Company relating to the ETC OLP business prior to closing, $433.9 million of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to the Parent Company and an affiliate of the Parent Company contributed an office building to ETC OLP. The Parent Company also received 7,485,030 ETP Special Units as consideration for the project it had in progress to construct the Bossier Pipeline now referred to as the East Texas Pipeline. The ETP Special Units converted to ETP Common Units upon the East Texas Pipeline becoming commercially operational and such conversion being approved by ETP’s Unitholders. The East Texas Pipeline became commercially operational on June 21, 2004, and the ETP Unitholders approved the conversion of the ETP Special Units at a special meeting held on June 23, 2004.

Simultaneously with the transactions described in the preceding paragraph, the Parent Company obtained control of Heritage by acquiring all of the interests in ETP GP, formerly U.S. Propane, L.P., the General Partner of Heritage, and ETP GP’s General Partner, ETP LLC formerly U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30.0 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, ETP GP contributed its 1.0101% General Partner interest in HOLP to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) for $100.0 million.

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

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

Recent Acquisitions and Expansions

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

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

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

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

Other Developments

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

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

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

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

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

•

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

•

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

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

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

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

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

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

Parent Company – Energy Transfer Equity, L.P.

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

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

ETP’s Operations

ETC OLP (Midstream and Transportation and Storage Operations)

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

LOGO

Our midstream segment consists of the following:

•

The Southeast Texas System, a 4,250-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. The system includes the La Grange processing plant, the Madison processing plant, and seven treating facilities. This system is connected to the Katy Hub through the 55-mile Katy Pipeline and is also connected to the Oasis Pipeline, as well as two power plants.

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

•

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

•

Marketing operations through our producer services business, in which we market the natural gas that flows through our assets, referred to as on-system gas, and attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell the natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or our transportation pipelines. For the off-system gas, we purchase gas or act as an agent for small independent producers that do not have marketing operations. We develop relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business provides us with strategic insight and market intelligence, which may impact our expansion and acquisition strategy.

Our transportation and storage segment consists of the following:

•

The Oasis Pipeline, a 583-mile natural gas pipeline that directly connects the Waha Hub to the Katy Hub. The Oasis Pipeline is primarily a 36-inch diameter natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

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

–

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

–

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

–

allowing us to bypass our treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis Pipeline while continuing to meet pipeline quality specifications.

•

The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,100 miles of intrastate natural gas pipeline and related natural gas storage facilities. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub, the Katy Hub and the Carthage Hub, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 1.3 Bcf/d of natural gas and total working storage capacity of 12.4 Bcf of

natural gas. The ET Fuel System operates our Bethel natural gas storage facility, with a working capacity of 6.4 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Integrated into our ET Fuel System is our Fort Worth Basin Pipeline, which became operational on May 26, 2005. The Fort Worth Basin Pipeline is a 55-mile, 24-inch natural gas pipeline that connects our existing pipelines in north Texas and provides transportation for natural gas production from the Barnett Shale producing area. The completion of the Fort Worth Basin Pipeline is the first part of our previously disclosed expansion program that was implemented to integrate our 36-inch Katy Pipeline and the Southeast Texas System assets with the ET Fuel System and the Houston Pipeline System.

•

The East Texas Pipeline is a 148-mile natural gas pipeline that connects three treating facilities, one of which we own, with our Southeast Texas System. This pipeline was the first phase of a multi-phased project that increased service to producers in East and North Central Texas and provided access to the Katy Hub. The East Texas Pipeline expansion had an initial capacity of over 400 MMcf/d which increased to the current capacity of 675 MMcf/d with the addition of the Grimes County Compressor Station. Over 500 MMcf/d of pipeline capacity is contracted under long-term agreements with XTO Energy Inc. and other producers.

•

The Houston Pipeline System is comprised of approximately 4,200 miles of intrastate natural gas pipeline with an aggregate capacity of 2.4 Bcf/d, the underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast of Texas, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The Houston Pipeline System is well situated to gather gas in many of the major gas producing areas in Texas and has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contributes to our overall ability to play an important role in the Texas natural gas markets. The Houston Pipeline System is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and our operation of the Bammel storage facility. The Bammel storage facility has a total working gas capacity of approximately 65 Bcf and has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.

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

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

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


	For the Years Ended August 31,
	2006	2005	2004	2004
			(Actual)	(Aggregate)
Retail Gallons Sold (in millions)	429.1	406.3	226.2	397.9

We present retail gallons sold for fiscal year 2004 on the basis of (1) an aggregate total reflecting Heritage’s historical results from September 1, 2003 until the closing of the Energy Transfer Transactions on January 19, 2004, and (2) Heritage’s historical results reflecting the actual results for the fiscal year ended August 31, 2004, for comparability purposes only. The aggregate information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

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

Business Strategy

The Parent Company Business Strategy

Our primary business objective is to increase our cash distributions to our Unitholders by actively assisting ETP in executing its business strategy by assisting in identifying, evaluating, and pursuing acquisitions and growth opportunities. In general, we expect that we will allow ETP the first opportunity to pursue any acquisition or internal growth project that may be presented to us which is within the scope of ETP’s operations or business strategy. In the future, we may also support the growth of ETP through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.

ETP’s Business Strategy

ETP’s primary objective is to increase Unitholder distributions and the value of its Common Units. We believe ETP has engaged, and will continue to engage, in a well-balanced plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of our existing assets.

ETP intends to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each ETP Common Unit. We believe that by pursuing independent operating and growth strategies for ETP’s midstream, transportation and storage and propane businesses, we will be best positioned to achieve our objectives.

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

Midstream and Transportation and Storage Business Strategies

Enhance profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes of natural gas, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.

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

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

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

operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets. We will also pursue midstream, transportation and storage asset acquisition opportunities in other regions of the U.S. with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. We believe that we will be well positioned to benefit from any additional acquisition opportunities that may arise as a result of the ongoing divestiture of midstream assets by large industry participants.

Propane Business Strategies

Pursue internal growth opportunities. In addition to pursuing expansion through acquisitions, we have aggressively focused on high return internal growth opportunities at our existing customer service locations. We believe that by concentrating our operations in areas experiencing higher-than-average population growth, we are well positioned to achieve internal growth by adding new customers.

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

Maintain low-cost, decentralized operations. We focus on controlling costs, and we attribute our low overhead costs primarily to our decentralized structure. By delegating all customer billing and collection activities to the customer service location level, as well as delegating other responsibilities to the operating level, we have been able to operate without a large corporate staff. In addition, our customer service location level incentive compensation program encourages employees at all levels to control costs while increasing revenues.

Competitive Strengths

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

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

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

Midstream and Transportation and Storage Business Strengths

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

Our assets provide marketing flexibility through our access to numerous markets and customers. The combination of our Oasis Pipeline and our Southeast Texas System provides our customers direct access to the Waha and Katy Hubs and to virtually all other market areas in the United States via interconnections with major intrastate and interstate natural gas pipelines. Furthermore, our Oasis Pipeline is tied directly or indirectly to a number of major power generation facilities in Texas as well as several industrial and utility end-users. With the acquisition of the ET Fuel System in June 2004, the HPL acquisition in January 2005, and the completion of the East Texas Pipeline

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

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

Our ability to bypass our La Grange processing plant reduces our commodity price risk. A significant benefit of our ownership of the Oasis Pipeline is that we can elect not to process natural gas at our La Grange processing plant when processing margins (or the difference between NGL sales prices and the cost of natural gas) are unfavorable. Instead of processing the natural gas, we are able to deliver natural gas meeting pipeline quality specifications by blending rich gas, or gas with a high NGL content, from the Southeast Texas System with lean gas, or gas with a low NGL content, transported on the Oasis Pipeline. This enables us to sell the blended natural gas for a higher price than we would have been able to realize upon the sale of NGLs if we had to process the natural gas to extract NGLs.

The Houston Pipeline System enables us to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. The Bammel natural gas storage facility, acquired when we purchased the Houston Pipeline System, has a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 600 MMcf/d peak injection rate. Therefore, we are able to purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. In addition, the Bammel natural gas storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.

Propane Business Strengths

Geographically diverse retail propane network. We believe our geographically diverse network of retail propane assets reduces our exposure to unfavorable weather patterns and economic downturns in any one geographic region, thereby reducing the volatility of our cash flows.

Experience in identifying, evaluating and completing acquisitions. We follow a disciplined acquisition strategy that concentrates on propane companies that (1) are located in geographic areas experiencing higher-than-average population growth, (2) provide a high percentage of sales to residential customers, (3) have a strong reputation for quality service, and (4) own a high percentage of the propane tanks used by their customers. In addition, we attempt to capitalize on the reputations of the companies we acquire by maintaining local brand names, billing practices and employees, thereby creating a sense of business continuity which minimizes customer loss. We believe that this strategy has also helped to make us an attractive buyer for many propane acquisition candidates from a seller’s viewpoint.

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

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

Decentralized operating structure and entrepreneurial workforce. We believe that our decentralized propane operations foster an entrepreneurial corporate culture by: (1) having operational decisions made at the customer service location and operating level, (2) retaining billing, collection and pricing responsibilities at the local and operating level, and (3) rewarding employees for achieving financial targets at the local level.

Midstream Natural Gas Industry Overview

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing and transportation and NGL fractionation and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

Natural gas has widely varying quality and composition, depending on the field, the formation or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, though most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline, that may be removed by a number of processing methods. Most raw materials produced at the wellhead are not suitable for long-haul pipeline transportation or commercial use and must be compressed, transported via pipeline to a central processing facility, and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of the gas.

Demand for natural gas. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, in its 2006 annual outlook, total domestic consumption of natural gas is expected to increase by over 0.7% per annum, from an estimated 22.4 Tcf consumed in 2004 to 26.9 Tcf in 2030. During the five-year period ended December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, with average domestic production of approximately 18.9 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.

Natural gas compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.

Natural gas treating. Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.

Natural gas processing. Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.

Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.

Propane Industry Overview

Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Retail propane use falls into three broad categories: (1) residential applications, (2) industrial, commercial and agricultural applications and (3) other retail applications, including motor fuel sales. In our wholesale operations, we sell propane principally to governmental agencies and industrial end-users.

Propane is extracted from natural gas at processing plants or separated from crude oil during the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is naturally colorless and odorless. An odorant is added to allow its detection. Like natural gas, propane is a clean burning fuel and is considered an environmentally preferred energy source.

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources has been increasing as a result of reduced utility regulation. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a significantly less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in the United States has resulted in the availability of natural gas in many areas that previously depended upon propane. Although the extension of natural gas pipelines tends to displace propane distribution in areas affected, we believe that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Even though propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to another. According to industry publications, propane accounts for 6 1/2% of household energy consumption in the United States.

In addition to competing with alternative energy sources, we compete with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Most of our customer service locations compete with five or more marketers or distributors in their area of operations. Each retail distribution outlet operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. The typical retail distribution outlet generally has an effective marketing radius of approximately 50 miles, although in certain rural areas the marketing radius may be extended by satellite locations.

The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers.

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

The Midstream and Transportation and Storage Segments

Competition

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

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

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

Credit Risk and Customers

We have a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users and customers in the refining and petrochemical industries. We are diligent in attempting to ensure that we issue credit to credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability.

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

Regulation

Regulation by FERC of Interstate Natural Gas Pipelines. Under the Natural Gas Act (“NGA”), the Federal Energy Regulatory Commission (“FERC”) generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” service includes storage service. Currently we do not own any interstate natural gas transportation facilities, so FERC does not directly regulate any of our pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

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the certification and construction of new facilities;

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the extension or abandonment of services and facilities;

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the maintenance of accounts and records;

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the acquisition and disposition of facilities;

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the initiation and discontinuation of services; and

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various other matters.

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

In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines’ rates and rules and policies that may affect rights of access to natural gas transportation capacity.

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

Intrastate Pipeline Regulation. Our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”), which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service set forth in the pipeline’s statement of operating conditions are subject to FERC review and approval. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC approved Statement of Operating Conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.

Our intrastate pipeline and storage operations in Texas are subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The TRRC has authority to ensure that rates charged by intrastate pipelines for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

Sales of Natural Gas. Sales for resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates are subject to FERC regulation unless the gas is produced by the pipeline or affiliate. Under current federal rules, however, the price at which we sell natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. Effective as of January 12, 2004, the FERC’s rules require pipelines (including intrastate pipelines) and their affiliates who sell gas in interstate commerce subject to FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate such code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by FERC. FERC denied rehearing of these rules on May 19, 2004, but the rules are still subject to possible court appeals. We cannot predict the outcome of these further proceedings, but do not believe we will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines in Texas and Louisiana that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. Our Chalkley System is regulated as an intrastate transporter, and the Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and Federal levels and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design,

installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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

Pipeline Safety. The states in which we conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended, (the “NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities from jurisdiction under that statute. The portions of our facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to our intrastate natural gas pipelines.

Propane Segment

Products, Services and Marketing

We distribute propane through a nationwide retail distribution network consisting of 442 customer service locations in 41 states. Our operations are concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States. We serve more than one million active customers. Historically, approximately two-thirds of our retail propane volumes and substantially all of our propane-related operating income is attributable to sales during the six-month peak-heating season from October through March, as many customers use propane for heating purposes. Consequently, sales and operating profits are normally concentrated in the first and second fiscal quarters, while cash flows from operations are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak season. To the extent necessary, we will reserve cash from peak periods for distribution to Unitholders during the warmer seasons.

Typically, customer service locations are found in suburban and rural areas where natural gas is not readily available. Generally, such locations consist of a one to two acre parcel of land, an office, a small warehouse and service facility, a dispenser and one or more 18,000 to 30,000 gallon storage tanks. Propane is generally transported from refineries, pipeline terminals, leased storage facilities and coastal terminals by rail or truck transports to our customer service locations where it is unloaded into storage tanks. In order to make a retail delivery of propane to a customer, a bobtail truck, which generally holds 2,500 to 3,000 gallons of propane, is loaded with propane from the storage tank. Propane is then delivered to the customer by the bobtail truck and pumped into a stationary storage tank on the customer’s premises. We also deliver propane to retail customers in portable cylinders. We also deliver propane to certain other bulk end-users of propane in tractor-trailer transports, which typically have an average capacity of approximately 10,500 gallons. End-users receiving transport deliveries include industrial customers, large-scale heating accounts, mining operations and large agricultural accounts.

We encourage our customers whose propane needs are temperature sensitive to implement a regular delivery schedule. Many of our residential customers receive their propane supply pursuant to an automatic delivery system, which eliminates the customer’s need to make an affirmative purchase decision and allows for more efficient route scheduling. We also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances.

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

The propane business is very seasonal with weather conditions significantly affecting demand for propane. We believe that the geographic diversity of our operations helps to reduce our overall exposure to less than favorable weather conditions in any particular region of the United States. Although overall demand for propane is affected by climate, changes in price and other factors, we believe our residential and commercial business to be relatively stable due to the following characteristics:

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residential and commercial demand for propane has been relatively unaffected by general economic conditions due to the largely non-discretionary nature of most propane purchases;

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loss of customers to competing energy sources has been low due to the lack of availability or the high cost of alternative fuels;

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the tendency of our customers to remain with us due to the product being delivered pursuant to a regular delivery schedule and to our ownership as of August 31, 2006 of approximately 84% of the storage tanks utilized by our customers, which prevents fuel deliveries from competitors; and

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our historic ability to more than offset customer losses through internal growth of our customer base in existing markets.

Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate can significantly affect the total volumes of propane that we sell and the margins realized thereon and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.

Propane Supply and Storage

Our supplies of propane historically have been readily available from our supply sources. We purchase from over 50 energy companies and natural gas processors at numerous supply points located in the United States and Canada. In the fiscal year ended August 31, 2006, Enterprise Products Operating L.P. (“Enterprise”) and Targa Liquids (“Targa”) provided approximately 27.0%, and 18.0% of our combined total propane supply, respectively. In addition, M-P Energy Partnership, a Canadian partnership in which our wholly-owned subsidiary, M.P. Oils, Ltd., owns a 60% interest procured 22.0% of our combined total propane supply during the fiscal year ended August 31, 2006. M-P Energy Partnership buys and sells propane for its own account and supplies propane to us for our northern United States operations. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010.

We believe that if supplies from Enterprise or Targa were interrupted we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Aside from Enterprise, Targa, and the supply procured by M-P Energy Partnership, no single supplier provided more than 10% of our total domestic propane supply during the fiscal year ended August 31, 2006. We believe that our diversification of suppliers will enable us to purchase all of our supply needs at market prices without a material disruption of our operations if supplies are interrupted from any of our existing sources. Although we cannot assure you that supplies of propane will be readily available in the future, we expect a sufficient supply to continue to be available. However, increased demand for propane in periods of severe cold weather, or otherwise, could cause future propane supply interruptions or significant volatility in the price of propane.

Except for Titan’s supply agreement, we typically enter into one-year supply agreements. The percentage of contract purchases may vary from year to year. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or at the current prices established at major delivery or storage points, and some contracts include a pricing formula that typically is based on these market prices. Most of these agreements provide maximum and minimum seasonal purchase guidelines. We receive our supply of propane predominately through railroad tank cars and common carrier transport.

Because our profitability is sensitive to changes in wholesale propane costs, we generally seek to pass on increases in the cost of propane to customers. We have generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane, but there is no assurance that we will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, our profitability will be sensitive to changes in wholesale propane prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

We lease space in larger storage facilities in Michigan, Arizona, New Mexico, and Texas, and smaller storage facilities in other locations, and have the opportunity to use storage facilities in additional locations when we “pre-buy” product from sources having such facilities. We believe that we have adequate third party storage to take advantage of supply purchasing advantages as they may occur from time to time. Access to storage facilities allows us to buy and store large quantities of propane during periods of low demand, which generally occur during the summer months, or at favorable prices, thereby helping to ensure a more secure supply of propane during periods of intense demand or price instability.

Pricing Policy

Pricing policy is an essential element in the marketing of propane. We rely on regional management to set prices based on prevailing market conditions and product cost, as well as local management input. All regional managers are advised regularly of any changes in the posted price of each customer service location’s propane suppliers. In most situations, we believe that our pricing methods will permit us to respond to changes in supply costs in a manner that protects our gross margins and customer base; to the extent such protection is possible. In some cases, however, our ability to respond quickly to cost increases could occasionally cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.

Billing and Collection Procedures

Customer billing and account collection responsibilities for our propane operations are retained at the local customer service locations. We believe that this decentralized approach is beneficial for several reasons:

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the customer is billed on a timely basis;

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the customer is more apt to pay a “local” business;

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cash payments are received more quickly; and

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local personnel have a current account status available to them at all times to answer customer inquiries.

Because propane sales to residential and commercial customers are affected by winter heating season requirements, our propane operations generally generate higher operating revenues and net income during the period from October through March of each year and lower operating revenues and, in some cases, lower net income or net losses during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather-sensitive.

Gross profit margins are not only affected by weather patterns but also by changes in customer mix. For example, sales to residential customers generate higher margins than sales to other customer groups, such as commercial or agricultural customers. Wholesale margins are substantially lower than retail margins. In addition, gross profit margins vary by geographic region. Accordingly, a change in customer or geographic mix can affect gross profit without necessarily affecting total revenues.

Government Regulation and Environmental Matters

The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations can impair our business activities that affect the environment in many ways, such as:

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

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limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted;

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requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and

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imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms.

Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. We have implemented environmental programs and policies designed to avoid potential liability and cost under applicable environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, risks of process upsets, accidental releases or spills are associated with our operations, and we cannot assure you that we will not incur significant costs and liabilities if such upsets, releases, or spills were to occur. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment, including those arising out of historical operations conducted by predecessors. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although “petroleum” is excluded from the definition of hazardous substance under CERCLA, we will generate materials in the course of our operations that may be regulated as hazardous substances. We also may incur liability under the Resource Conservation and Recovery Act, also known as “RCRA,” which imposes requirements related to the management and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of our operations, we may generate unrecovered petroleum product wastes as well as ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous or solid wastes.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. A predecessor company acquired by us in July 2001 had previously received and responded to a request for information from the U.S. Environmental Protection Agency or “EPA” regarding its potential contribution to widespread groundwater contamination in San Bernardino, California, known as the Newmark Groundwater Contamination Superfund site. We have not received any follow-up correspondence from EPA on the matter since our acquisition of the predecessor company in 2001. In addition, through our acquisitions of ongoing businesses, we are currently involved in several remediation projects that have cleanup costs and related liabilities. As of August 31, 2006 an accrual of $1.4 million was recorded in our consolidated balance sheet to cover estimated environmental liabilities

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

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties, as well as significant remedial obligations. We believe that we are in substantial compliance with the Clean Water Act. We currently expect to incur costs of approximately $0.1 million over the next year to upgrade or modify certain facilities as required under our spill prevention, control and countermeasures, or “SPCC,” plans.

The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Failure to comply with these laws and regulations could expose us to civil and criminal enforcement actions. We received a state-issued “Pipeline Facilities” air emissions permit on June 30, 2005 for our Prairie Lea Compressor Station in Caldwell County, Texas, which historically has been designated as a “grandfathered facility” and, thus, was excluded from state air emissions permitting requirements. In order to comply with the terms of this permit and associated regulations requiring specified reductions in nitrogen oxides or “NOx” emissions by March 1, 2007, we are planning to modify the compressor engines at the facility during 2006, at an estimated cost of $2.0 million. In addition, we are currently pursuing agency-approved baseline monitoring of NOx emissions from our Katy Compressor Station in Harris County, Texas, which is in a non-attainment area for ozone. Once we develop this NOx baseline, we have been planning to purchase a sufficient amount of NOx emission allowances that would allow the facility to continue at its current level of operation in the non-attainment area, at an estimated cost of $2.3 million. These plans are subject to possible change however, as the non-attainment area is currently transitioning from a 1-hour ozone non-attainment area to an 8-hour ozone non-attainment area, which transition we expect will result in the adoption of further regulations that will perhaps change the extent to which NOx emissions reductions may be required.

Our operations are subject to regulation by the U.S. Department of Transportation or “DOT” under the Hazardous Liquid Pipeline Safety Act, or “HLPSA,” pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA requires any entity which owns or operates pipeline facilities to permit access to and allow copying of records and to make certain reports and provide information as required by the DOT. While we believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our operations or financial position. Moreover, the DOT, through the Office of Pipeline Safety, has promulgated rules requiring pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact “high consequence areas,” including areas with specified population densities. Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing, or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. We estimate that compliance with these rules will result in capital costs of $21.3 million during the period between the remainder of calendar year 2006 to 2008 as well as operating and maintenance costs of $24.8 million during the three year period.

We are subject to the requirements of the federal Occupational Safety and Health Act, also known as OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are

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

Employees

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

SEC Reporting

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

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

ITEM 1A. RISK FACTORS

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

Risks Inherent in an Investment in Us:

Our only assets are our partnership interests, including the incentive distribution rights, in ETP and, therefore, our cash flow is dependent upon the ability of ETP to make distributions in respect of those partnership interests.

The amount of cash that ETP can distribute to its partners, including us, each quarter depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

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

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the level of throughput in its processing and treating operations;

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

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the price of natural gas;

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the relationship between natural gas and NGL prices;

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the weather in our operating areas;

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

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

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the level of its operating costs;

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prevailing economic conditions; and

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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:

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the level of capital expenditures it makes;

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the cost of acquisitions, if any;

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

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its debt service requirements;

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fluctuations in its working capital needs;

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

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restrictions on distributions contained in its debt agreements; and

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

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

Furthermore, you should be aware that the amount of cash that ETP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ETP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income. Please read “Risks Related to Energy Transfer Partners’ Business” included in this Item 1A for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.

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

The source of our earnings and cash flow is cash distributions from ETP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP makes to its partners. We cannot assure you that ETP will continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP to us.

Our ability to distribute cash received from ETP to our Unitholders is limited by a number of factors, including:

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interest expense and principal payments on our indebtedness;

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restrictions on distributions contained in any current or future debt agreements;

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our general and administrative expenses;

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expenses of our subsidiaries other than ETP, including tax liabilities of our corporate subsidiaries, if any;

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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

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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.

Affiliates of our General Partner own approximately 75.0% of our Common Units on a fully diluted basis, a sufficient number to change our cash distribution policy, amend our Partnership Agreement and block any attempt to remove our General Partner.

Our affiliates own approximately 75.0% of our outstanding Common Units on a fully diluted basis. In addition, some of these owners are members of the Board of Directors of our General Partner. Because these owners have the ability to amend our Partnership Agreement and change our cash distribution policy, we cannot assure you that we will maintain or increase the distribution we pay to our Common Unitholders.

Unlike the holders of common stock in a corporation, our Unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our Unitholders do not have the ability to elect our General Partner or the officers or directors of our General Partner.

Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. Our General Partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding units. Because affiliates of our General Partner own approximately 158 million of our outstanding units, it will be particularly difficult for our General Partner to be removed without the consent of such affiliates. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

A reduction in ETP’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.

Our direct and indirect ownership of 100% of the incentive distribution rights in ETP (50% prior to November 1, 2006), through our ownership of equity interests in Energy Transfer Partners GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. The amount of the cash distributions that we received from ETP during our fiscal year 2006 related to our ownership interest in the incentive distribution rights has increased at a more rapid rate than the amount of the cash distributions related to our 2% General Partner interest in ETP and our ETP Common Units. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which Energy Transfer Partners GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per Common Unit per quarter would reduce Energy Transfer Partners GP’s percentage of the incremental cash distributions above $0.3175 per Common Unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our 2% General Partner interest in ETP and our ETP Common Units.

Neither we nor ETP will be prohibited from competing with each other.

Neither our Partnership Agreement nor the Partnership Agreement of ETP prohibits us from owning assets or engaging in businesses that compete directly or indirectly with ETP or prohibit ETP from owning assets or engaging in businesses that compete directly or indirectly with us, except that ETP’s Partnership Agreement prohibits us from engaging in the retail propane business in the United States. In addition, we may acquire, construct or dispose of any assets in the future without any obligation to offer ETP the opportunity to purchase or construct any of those assets, and ETP may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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.

Our General Partner has only one executive officer, and we are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.

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

Moreover, we rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Ray C. Davis and Kelcy L. Warren, the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as H. Michael Krimbill, R.C. Mills and Mackie McCrea. Messrs. Davis and Warren have been integral to the success of ETP’s midstream and transportation and storage businesses because of their ability to identify and develop strategic business opportunities. Losing their leadership could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.

ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

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

Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.

Your liability as a limited partner may not be limited, and our Unitholders may have to repay distributions or make additional contributions to us under limited circumstances.

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a General Partner if you participate in the “control” of our business. Our General Partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the

partnership that are expressly made without recourse to our General Partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Under limited circumstances, our Unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, neither Energy Transfer Equity nor ETP may make a distribution to its Unitholders if the distribution would cause Energy Transfer Equity’s or ETP’s respective liabilities to exceed the fair value of their respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

If in the future we cease to manage and control ETP, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control ETP and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

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

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

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

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

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

•

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

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

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

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

Prior to our IPO there was no public market for our Common Units. An active market for our Common Units may not be sustained. The initial public offering price of our Common Units was determined by negotiations between us and the underwriters, based on several factors that we discuss in the “Underwriting” section of our prospectus. This price may not be indicative of the market price for our Common Units after the initial public offering. The market price of our Common Units could be subject to significant fluctuations and may decline below the initial public offering price. You may be unable to resell your Common Units at or above the initial public offering price. The following factors could affect our unit price:

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ETP’s operating and financial performance and prospects;

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quarterly variations in the rate of growth of our financial indicators, such as distributable cash per unit, net income and revenues;

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changes in revenue or earnings estimates or publication of research reports by analysts;

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speculation by the press or investment community;

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sales of our Common Units by our Unitholders;

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actions by our existing Unitholders prior to their disposition of our Common Units;

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announcements by ETP or its competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;

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general market conditions; and

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domestic and international economic, legal and regulatory factors related to ETP’s performance.

The equity markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Common Units. In addition, potential investors may be deterred from investing in our Common Units for various reasons, including the very limited number of publicly-traded entities whose assets consist almost exclusively of partnership interests in a publicly-traded partnership. The lack of liquidity may also contribute to significant fluctuations in the market price of our Common Units and limit the number of investors who are able to buy our Common Units.

Our Common Units and ETP’s Common Units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our Common Units and ETP’s Common Units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:

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ETP’s cash distributions to its common Unitholders have a priority over our incentive distribution rights in ETP;

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we participate in ETP’s General Partner’s distributions and the incentive distribution rights, and ETP’s Common Unitholders do not; and

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we may enter into other businesses separate from ETP or any of its affiliates.

Our Partnership Agreement restricts the rights of Unitholders owning 20% or more of our units.

Our Unitholders’ voting rights are restricted by the provision in our Partnership Agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner and its affiliates, cannot be voted on any matter. In addition, our Partnership Agreement contains provisions limiting the ability of our Unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our Unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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

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

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

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

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

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

Risks Related to Conflicts of Interest

Although we control ETP through our ownership of its General Partner, ETP’s General Partner owes fiduciary duties to ETP and ETP’s Unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including ETP’s General Partner, on the one hand, and ETP and its Limited Partners, on the other hand. The directors and officers of ETP’s General Partner have fiduciary duties to manage ETP in a manner beneficial to us, its owner. At the same time, the General Partner has a fiduciary duty to manage ETP in a manner beneficial to ETP and its limited partners. The board of directors of ETP’s General Partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

For example, conflicts of interest may arise in the following situations:

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the allocation of shared overhead expenses to ETP and us;

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand;

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the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business;

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the determination whether to make borrowings under ETP’s revolving working capital facility to pay distributions to ETP’s partners; and

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any decision we make in the future to engage in business activities independent of ETP.

The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s General Partner.

Conflicts of interest may arise because of the relationships between ETP’s General Partner, ETP and us. Our General Partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s General Partner, and have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and ETP’s Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

Our General Partner’s affiliates may compete with us.

Our Partnership Agreement provides that our General Partner will be restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. Except as provided in our Partnership Agreement, affiliates of our General Partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us and our Unitholders, which may permit them to favor their own interests to the detriment of us and our Unitholders.

Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us and our Unitholders, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over the interests of our Unitholders. These conflicts include, among others, the following:

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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.

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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.

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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.

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Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.

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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.

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

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

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

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

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

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

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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;

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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

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

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

Our General Partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Affiliates of our General Partner own approximately 75.0% of our Common and Class B Units.

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

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

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

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

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

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our Unitholders’ proportionate ownership interest in ETP will decrease;

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

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the market price of our Common Units may decline.

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

Risks Related to Energy Transfer Partners’ Business

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

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

Income from ETP’s midstream, transportation and storage business is exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the Southeast Texas System and at ETP’s Houston Pipeline System, ETP purchases natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gathers and delivers the natural gas to pipelines where ETP typically resells the natural gas at the index price. Generally, the gross margins ETP realizes under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

For a portion of the natural gas gathered at the Southeast Texas System, ETP enters into percentage-of-proceeds arrangements and keep-whole arrangements, pursuant to which ETP agrees to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remits to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sells the volumes it keeps to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s results of operations. Under keep-whole arrangements, ETP generally sells the NGLs produced from its gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, ETP’s revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if ETP is not able to bypass its processing plants and sell the unprocessed natural gas.

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

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

ETP’s Oasis Pipeline, East Texas Pipeline System, ET Fuel System and Houston Pipeline System receive fees for transporting natural gas for its customers. Although a significant amount of the pipeline capacity of the East Texas Pipeline System and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of ETP’s transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels. ETP’s fuel retention fees are also directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase ETP’s fuel retention fees, and decreases in natural gas prices tend to decrease its fuel retention fees.

The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:

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the impact of weather on the demand for oil and natural gas;

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the level of domestic oil and natural gas production;

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the availability of imported oil and natural gas;

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actions taken by foreign oil and gas producing nations;

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the availability of local, intrastate and interstate transportation systems;

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the price, availability and marketing of competitive fuels;

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the demand for electricity;

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the impact of energy conservation efforts; and

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the extent of governmental regulation and taxation.

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

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

ETP’s success depends upon its ability to continually contract for new sources of natural gas supply.

In order to maintain or increase throughput levels on ETP’s gathering and transportation pipeline systems and asset utilization rates at its treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and it may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting ETP’s ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near ETP’s gathering systems or in areas that provide access to its transportation pipelines or markets to which its systems connect. The primary factors affecting ETP’s ability to attract customers to its transportation pipelines consist of its access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.

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

A substantial portion of ETP’s assets, including its gathering systems and its processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. In particular, the Southeast Texas System covers portions of the Austin Chalk, Buda, Georgetown, Edwards, Wilcox and other producing formations in southeast Texas, which is collectively referred to as the Austin Chalk trend. This natural gas producing region has generally been characterized by high initial flow rates followed by steep initial declines in production. Accordingly, ETP’s cash flows will also decline unless it is able to access new supplies of natural gas by connecting additional production to these systems.

ETP’s transportation pipelines are also dependent upon natural gas production in areas served by its pipelines or in areas served by other gathering systems or transportation pipelines that connect with its transportation pipelines. A material decrease in natural gas production in ETP’s areas of operation or in other areas that are connected to ETP’s areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP handles, which would reduce ETP’s revenues and operating income. In addition, ETP’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the natural decline rate in ETP’s currently connected supplies.

The volumes of natural gas ETP transports on its pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel Hub, the four major natural gas trading hubs served by ETP’s pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those ETP operates.

ETP may not be able to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for qualified assets.

ETP’s strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage, propane and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance its ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. ETP regularly considers and enters into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that ETP believes will present opportunities to realize synergies and increase its cash flow.

Consistent with ETP’s acquisition strategy, management is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. ETP cannot assure you that its current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to ETP.

In addition, ETP is experiencing increased competition for the assets it purchases or contemplates purchasing. Increased competition for a limited pool of assets could result in ETP losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit ETP’s ability to fully execute its growth strategy. Inability to execute its growth strategy may materially adversely impact the market price of ETP’s securities.

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

Historically, ETP’s results of operations and its ability to grow and to increase distributions to Unitholders has depended principally on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit. ETP’s acquisition strategy is based, in part, on its expectation of ongoing divestitures of pipeline assets by large industry participants. A material decrease in such divestitures would limit ETP’s opportunities for future acquisitions and could adversely affect its business, results of operations, financial condition and cash flows available for distribution to ETP’s Unitholders, including the Parent Company.

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

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

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

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because ETP is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does.

Furthermore, even if ETP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in no increase or even a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP may:

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fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

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decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;

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significantly increase its interest expense or financial leverage if ETP incurs additional debt to finance acquisitions;

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encounter difficulties operating in new geographic areas or new lines of business;

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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;

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be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;

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less effectively manage its historical assets, due to the diversion of ETP management’s attention from other business concerns; or

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incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that ETP will consider.

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

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

ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System, and the loss of any of these key producers could adversely affect its financial results.

As of ETP’s fiscal year ended August 31, 2006, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied ETP with approximately 44% of the Southeast Texas System’s natural gas supply. ETP is not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply ETP, ETP would be adversely affected unless it was able to acquire comparable supplies of natural gas from other producers.

ETP depends on key customers to transport natural gas on its East Texas Pipeline System and ET Fuel System.

ETP has entered into nine- and ten-year fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on ETP’s pipelines. ETP has also entered into an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which is referred to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. ETP has also entered into two eight-year natural gas storage contracts with

TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

Federal, state or local regulatory measures could adversely affect ETP’s business.

As a natural gas gatherer and intrastate pipeline company, ETP is generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects ETP’s business and the market for its products. In recent years, FERC has pursued pro-competitive policies in the regulation of interstate natural gas pipelines. However, ETP cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. The rates, terms and conditions of some of the transportation and storage services ETP provides on the Oasis Pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC approval. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

ETP’s intrastate natural gas transportation and storage facilities are subject to state regulation in Texas and Louisiana, the states in which ETP operate these types of pipelines. ETP’s intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s business may be adversely affected.

ETP’s pipeline operations are also subject to ratable take and common purchaser statutes in Texas and Louisiana, the states where ETP operates. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP operates that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s business.

ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the ET Fuel System and the Houston Pipeline System natural gas storage facilities are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRCC–jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. The TRRC’s regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.

The states in which ETP conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.

Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws could result in the imposition of administrative, civil and criminal remedies.

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

ETP’s natural gas midstream, transportation and storage, as well as its propane, businesses are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for its operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from ETP’s pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from its operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

ETP may incur substantial environmental costs and liabilities because the underlying risks are inherent to its operations. Joint and several, strict liability may be incurred under environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons or wastes on, under, or from its properties and facilities, many of which have been used for industrial activities for a number of years. Private parties, including the owners of properties through which ETP’s gathering systems pass or facilities where its petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position.

Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect ETP’s revenues and cash flow.

Users of ETP’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s pipelines. Any reduction in volumes transported in ETP’s pipelines would adversely affect its revenues and cash flow.

ETP encounters competition from other midstream, transportation and storage companies and propane companies.

ETP experiences competition in all of its markets. ETP’s principal areas of competition include obtaining natural gas supplies for the Southeast Texas System and natural gas transportation customers for the Oasis Pipeline, the East Texas Pipeline System and the ET Fuel System. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems owned by Duke Energy Field Services, LLC. The East Texas Pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale area of the Fort Worth Basin in north Texas. The ET Fuel System competes with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub, and the Fort Worth Basin Pipeline competes with other natural gas transportation pipelines serving the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that ETP competes with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P., and Enbridge, Inc. Some of ETP’s competitors may have greater financial resources and access to larger natural gas supplies than it does.

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

Texas Gulf Coast. As a result of ETP’s expanded market presence and diversification, ETP faces additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas, that may have greater financial resources and access to larger natural gas supplies than ETP does.

ETP’s propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:

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price,

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reliability and quality of service,

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responsiveness to customer needs,

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safety concerns,

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long-standing customer relationships,

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the inconvenience of switching tanks and suppliers, and

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the lack of growth in the industry.

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

One of the ways that ETP expects to grow its business is through the construction of additions to its existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and require the expenditure of significant amounts of capital that ETP will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, ETP’s revenues may not increase immediately following the completion of particular projects. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. Moreover, ETP may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.

ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its Unitholders, including the Parent Company.

The risks of nonpayment and nonperformance by ETP’s customers are a major concern in its business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP is subject to risks of loss resulting from nonpayment or nonperformance by its customers. Any substantial increase in the nonpayment and nonperformance by ETP’s customers could reduce its ability to make distributions to its Unitholders, including the Parent Company.

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

Because of ETP’s ownership of the Oasis Pipeline, it can generally elect to bypass the La Grange processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the Southeast Texas System with lean gas transported on the Oasis Pipeline. In some circumstances, such as when ETP does not have a sufficient amount of lean gas to blend with the volume of rich gas that it receives at the La Grange processing plant, ETP may have to process the rich gas. If ETP has to process when processing margins are unfavorable, its results of operations will be adversely affected.

ETP may be unable to retain existing customers or secure new customers, which would reduce its revenues and limit its future profitability.

The renewal or replacement of existing contracts with ETP’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets ETP serves.

For ETP’s fiscal year ended August 31, 2006, approximately 40% of its sales of natural gas were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP in the marketing of natural gas, ETP often competes in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on ETP’s profitability.

ETP’s storage business depends on neighboring pipelines to transport natural gas.

To obtain natural gas, ETP’s storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with ETP. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.

ETP’s pipeline integrity program may cause it to incur significant costs and liabilities.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of ETP’s current pipeline integrity testing programs, ETP estimated that compliance with this final rule for its existing transportation assets will result in capital costs of $21.3 million during the period between the remainder of calendar year 2006 to 2008, as well as operating and maintenance costs of $24.8 million during that period. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

Since weather conditions may adversely affect demand for propane, ETP’s financial conditions may be vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of ETP’s customers rely heavily on propane as a heating fuel. Typically, ETP sells approximately two-thirds of its retail propane volume during the peak-heating season of October through March. ETP’s results of operations can be adversely affected by warmer winter weather which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect ETP’s operating and financial results, its access to capital and its acquisition activities may be limited. Variations in weather in one or more of the regions where ETP operates can significantly affect the total volume of propane that ETP sells and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including periods of unseasonably cold or hot periods or dry weather conditions which may impact agricultural operations.

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

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

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

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

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

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

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

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, ETP’s profitability is sensitive to changes in energy prices, and in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, ETP may be unable to pass on these increases to its customers through retail or wholesale prices. Propane is a commodity and the price ETP pays for it can fluctuate significantly in response to changes in supply or other market conditions over which ETP has no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce ETP’s gross profits and could, if continued over an extended period of time, reduce demand by encouraging ETP’s retail customers to conserve their propane usage or convert to alternative energy sources.

ETP’s results of operations and its ability to make distributions or pay interest or principal on debt securities could be negatively impacted by price and inventory risk related to its propane business and management of these risks.

ETP generally attempts to minimize its cost and inventory risk related to its propane business by purchasing propane on a short-term basis under supply contracts that typically have a one-year term and at a cost that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure adequate supply sources are available during periods of high demand, ETP may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in its facilities, at major storage facilities owned by third parties or for future delivery. This strategy may not be effective in limiting ETP’s cost and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the cost at which ETP made such purchases, it could adversely affect its profits.

Some of ETP’s propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to ETP’s anticipated sales volumes under the commitments, ETP may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. ETP enters into such contracts and exercises such options at volume levels that it believes are necessary to manage these commitments. The risk management of ETP’s inventory and contracts for the future purchase of product could impair its profitability if the customers do not fulfill their obligations.

ETP also engages in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on ETP management’s estimates of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of ETP’s control occur, such activities could generate a loss in future periods and potentially impair its profitability.

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

During fiscal 2006, ETP purchased approximately 27% of its propane from Enterprise Products Operating L.P., approximately 18% from Targa Liquids, and approximately 22% of its propane from M-P Energy Partnership, the Canadian partnership in which ETP owns a 60% interest. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

Historically, a substantial portion of the propane that ETP purchases originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to ETP through major common carrier pipelines. Any significant interruption in the service at Mt. Belvieu or other major market points, or on the common carrier pipelines ETP uses, would adversely affect its ability to obtain propane.

Competition from alternative energy sources may cause ETP to lose propane customers, thereby reducing its revenues.

Competition in ETP’s propane business from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause ETP to lose customers, thereby reducing its revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect ETP’s operations.

Energy efficiency and technological advances may affect the demand for propane and adversely affect ETP’s operating results.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect ETP’s operations.

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. The value of our investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.

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

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

If ETP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

Current law may change, causing us or ETP to be treated as a corporation for federal income tax purposes or otherwise subjecting us or ETP to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or ETP as an entity, the cash available for distribution to you would be reduced.

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

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

The IRS may adopt positions that differ from the positions that we or ETP take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or ETP take. A court may not agree with some or all of the positions we or ETP take. Any contest with the IRS may materially and adversely impact the market for our Common Units or ETP’s Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by ETP and therefore indirectly by us, as a Unitholder and as the owner of the General Partner of ETP. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our Unitholders and thus will be borne indirectly by our Unitholders.

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

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

Only calendar year taxpayers may become partners.

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

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

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

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

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

We will treat each purchaser of Common Units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that do not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the Unitholder’s sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to the Unitholder’s tax returns.

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Substantially all of our pipelines, which are located in Texas and Louisiana, are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be

subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee.

Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations will be obtained, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

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

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

The transportation of propane requires specialized equipment. The trucks and railroad tank cars used for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of August 31, 2006, we utilized approximately 68 transport truck tractors, 68 transport trailers, 15 railroad tank cars, 1,772 bobtails and 2,831 other delivery and service vehicles, all of which we own. As of August 31, 2006, we owned approximately 1,135,800 customer storage tanks with typical capacities of 120 to 1,000 gallons that are leased or available for lease to customers. These customer storage tanks are pledged as collateral to secure the obligations of HOLP to its banks and the holders of its notes.

We utilize a variety of trademarks and trade names in our propane operations that we own or have secured the right to use, including “Heritage Propane” and “Titan Propane.” These trademarks and trade names have been registered or are pending registration before the United States Patent and Trademark Office or the various jurisdictions in which the trademarks or trade names are used. We believe that our strategy of retaining the names of the companies we have acquired has maintained the local identification of these companies and has been important to the continued success of these businesses. Some of our most significant trade names include Balgas, Bi-State Propane, Blue Flame Gas of Charleston, Blue Flame Gas of Mt. Pleasant, Blue Flame Gas, Carolane Propane Gas, Gas Service Company, EnergyNorth Propane, Gibson Propane, Guilford Gas, Holton’s L.P. Gas, Ikard & Newsom, Northern Energy, Sawyer Gas, ProFlame, Rural Bottled Gas and Appliance, ServiGas, and V-1 Propane, Coast Gas, Empiregas, Flame Propane, Graves Propane, Synergy Gas. We regard our trademarks, trade names and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

ITEM 3. LEGAL PROCEEDINGS

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

At the time of the Houston Pipeline System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”) and the parent companies of the HPL Entities were engaged in ongoing litigation with Bank of America that related to AEP’s acquisition of the Houston Pipeline in the Enron bankruptcy and Bank of America’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). At issue are matters relating to the ownership and certain rights to use the Cushion Gas. We refer to this litigation as the “Cushion Gas Litigation”. Under the terms of the purchase and sale agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.

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

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

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

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

None.

PART II

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

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Parent Company

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

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


	Price Range				Cash Distribution (1)
2006 Fiscal Year	High		Low		Cash Distribution (1)
Fourth Quarter Ended August 31, 2006	$	27.16	$	24.98	$	0.3125
Third Quarter Ended May 31, 2006	$	27.65	$	21.41	$	0.2375
Period Ended February 28, 2006 (2)	$	23.29	$	21.50	$	0.0578

(1)

Distributions are shown in the quarter with respect to which they were declared. For each of the indicated quarters for which distributions have been made, an identical per unit cash distribution was paid on any units subordinated to our Common Units outstanding at such time. Please see “Cash Distribution Policy” for a discussion of our policy regarding the payment of distributions.

(2)	High and low for the period ended February 28, 2006 represents the period from February 3, 2006 (the IPO date) to February 28, 2006.

Description of Units

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

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

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

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

Parent Company Cash Distribution Policy

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

Definition of Available Cash. Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

•

provide for the proper conduct of its business;

•

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

•

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

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

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


	2006		2005
Limited Partners -
Limited Partners (a)	$	34,010	$	666,751
Common Units		65,905		—
Class B Units		745		—
General Partner		599		4,861

Total distributions declared	$	101,259	$	671,612

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

Securities Authorized for Issuance Under Equity Compensation Plans

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

Changes in Securities and Recent Sales of Unregistered Securities

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

Issuer Purchases of Equity Securities

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


Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plan or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plan or Programs
June 1, 2006 through June 30, 2006	—		—	—	—
July 1, 2006 through July 31, 2006	9,642,757	$	24.66	—	—
August 1, 2006 through August 31, 2006	—		—	—	—

Total	9,642,757	$	24.66	—	—

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

ITEM 6. SELECTED FINANCIAL DATA

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

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

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

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

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

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


	Aquila Gas Pipeline						Energy Transfer Equity, L.P.
	Year Ended December 31, 2001			Nine Months Ended September 30, 2002			Eleven Months Ended August 31, 2003 (a)			Year Ended August 31,
	Year Ended December 31, 2001			Nine Months Ended September 30, 2002			Eleven Months Ended August 31, 2003 (a)			2004			2005			2006
Statement of Operations Data:
Revenues
Midstream segment	$	1,813,850		$	933,099		$	899,086		$	1,880,663		$	3,246,772		$	4,223,544
Transportation and storage segment		—			—			41,500			113,938			2,608,108			5,013,224
Eliminations		—			—			(9,559	)		(27,798	)		(471,255	)		(2,359,256	)
Propane segments		—			—			—			376,689			778,306			973,844
Other segment		—			—			—			3,465			6,867			7,740

Total revenues		1,813,850			933,099			931,027			2,346,957			6,168,798			7,859,096
Gross margin		98,589			53,035			105,589			365,533			787,283			1,290,780
Depreciation and amortization		30,779			22,915			11,870			56,242			105,751			129,636
Operating income		42,990			2,862			55,501			130,806			297,921			575,540
Interest expense		6,858			3,931			12,453			41,217			101,061			150,646
Gain on Energy Transfer Transactions		—			—			—			395,253			—			—
Minority interests in income from Continuing Operations		—			—			—			(35,164	)		(96,946	)		(303,752	)
Income from continuing operations before income tax expense		41,161			4,272			44,673			449,551			104,849			130,155
Income tax expense (benefit)(b)		15,403			(467	)		4,432			2,792			4,397			23,015
Income from continuing operations		25,758			4,739			40,241			446,759			100,452			107,140
Basic income from continuing operations per limited partner unit (c)		—			—			0.47			4.54			0.89			0.80
Diluted income from continuing operations per unit (c)		—			—			0.30			3.35			0.75			0.79
Cash distribution per unit		—			—			.03			1.36			2.66			2.56

Balance Sheet Data (at period end):
Current assets		144,396			116,831			223,897			481,868			1,453,730			1,302,736
Total assets		633,260			601,528			604,140			2,865,191			4,905,672			5,924,141
Current liabilities		194,816			144,076			169,967			404,917			1,244,785			1,020,787
Long-term debt (less current maturities)		66,250			66,250			196,000			1,071,158			2,275,965			3,205,646
Stockholders’ equity/Partners’ capital (deficit)		249,520			254,259			182,631			368,325			(88,137	)		45,751
Other Financial Data:
Cash flow provided by operating activities		65,198			12,987			70,675			122,098			38,133			310,782
Cash flow used in investing activities		(20,727	)		(487	)		(341,258	)		(731,831	)		(1,131,117	)		(1,244,406	)
Cash flow provided by (used in) financing activities		(44,471	)		(12,500	)		325,655			637,513			1,043,591			926,369
Capital expenditures
Maintenance and growth		23,944			5,486			11,914			109,688			196,459			680,164
Acquisition		—			—			340,187			622,929			1,131,844			586,185

(a)	On December 27, 2002, ETC OLP purchased the remaining 50% of Oasis Pipe Line. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After this date, Oasis Pipe Line’s results of operations are consolidated with ETC OLP as a wholly-owned subsidiary.

(b)

As a partnership, we are not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings and Heritage Service Corporation, are corporations that are subject to income taxes. Prior to 2003, Oasis Pipe Line was an equity method investment of ETC OLP, and taxes were netted against the equity method earnings. Aquila Gas Pipeline was a tax-paying corporation, and as such recognized income taxes related to its earnings in all periods presented.

(c)

Basic income from continuing operations per limited partner unit is computed by dividing income from continuing operations, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted income from continuing operations per limited partner unit is computed by dividing income from continuing operations (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per unit computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s unit-based compensation plans had been issued during the respective periods. Such units have been determined based on the treasury stock method.

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

RESULTS OF OPERATIONS

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

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

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

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

Overview

Parent Company – Energy Transfer Equity, L.P.

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

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

General

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

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

ETP’s Operations

Midstream and Transportation and Storage Segments

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

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

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

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

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

Retail and Wholesale Propane segments

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

The propane segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. In particular, our propane business is largely seasonal and dependent upon weather conditions in our service areas.

Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in our first and second fiscal quarters; however, cash flow from operations is generally greatest during our second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

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

The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. The wholesale propane segment’s margins are substantially lower than retail margins. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.

Amounts discussed below reflect 100% of the results of MP Energy Partnership. MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest.

Summary of Operating Financial Performance in fiscal 2006

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

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

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

Trends and Outlook

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

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

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

Recent Expansion Projects

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

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

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

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

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

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

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

Analytical Analysis

The Energy Transfer Transactions discussed previously were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquirer for accounting purposes. As a result, ETC OLP’s historical financial statements became our historical financial statements as the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to herein as Heritage.

The Energy Transfer Transactions affect the comparability of our financial statements for the year ended August 31, 2005 to the year ended August 31, 2004 because our consolidated financial statements for the year ended August 31, 2004 reflect the results of ETC OLP and its subsidiaries for the full period and the results of HOLP and HHI only from January 20, 2004 through August 31, 2004. The aggregate results in the propane segments disclosed below reflect Heritage’s historical results for the year ended August 31, 2004 combined with the historical results of Energy Transfer Company for the year ended August 31, 2004, and are presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

The comparability of our financial statements is also affected by our purchase of Titan in June 2006, HPL in January 2005 and ET Fuel System in June 2004 and the sale of ETC Oklahoma (“Elk City”) in April 2005. See Note 2 to our consolidated financial statements for a detailed discussion of our significant acquisitions and dispositions during fiscal years 2006, 2005 and 2004.

Analysis of Operating Data

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

Midstream


	Years Ended August 31,
	2006	2005	2004
Natural gas sales, MMBtu/d	1,552,753	1,578,833	1,026,773
NGL sales, Bbls/d	10,425	12,707	6,920

•

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

•

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

Transportation and Storage


	Years Ended August 31,
	2006	2005	2004
Natural gas MMBtu/d – transported	4,633,069	3,495,434	1,090,710
Natural gas MMBtu/d – sold	1,580,638	1,361,729	—

•

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

•

For the year ended August 31, 2005, transportation natural gas volumes increased by 2,404,724 MMBtu/d from 1,090,710 MMBtu/d to 3,495,434 MMBtu/d for the year ended August 31, 2005. The increase in transportation volumes is principally due to the increased volumes experienced on our Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, the completion of the East Texas Pipeline in June 2004, and additional transportation volumes from the HPL System acquisition. As noted above, the transportation and storage segment also generates revenue and margin from the sale of natural gas on the HPL System to its customers. The HPL System’s natural gas sales volumes were 1,361,729 MMbtu/d for the period from acquisition to August 31, 2005 and it processed 1,735 Bbls/d during the same period.

Propane


	Years Ended August 31,
	2006	2005	2004	2004
				(Aggregate)
Gallons sold
(in thousands)
Retail	429,118	406,334	226,209	397,862
Wholesale	79,348	70,047	35,719	64,399

•

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

•

For the year ended August 31, 2005 total retail propane gallons sold were 406.3 million gallons, compared to 226.2 million retail propane gallons reflected in the year ended August 31, 2004. The difference in retail gallons sold is partially due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting and ETC OLP had no propane operations prior to the Energy Transfer Transactions. As a comparison, we would have reflected an aggregate of 397.9 million retail gallons if the Energy Transfer Transactions would have occurred at the beginning of fiscal year 2004. The increase in fiscal year 2005 over fiscal year 2004 aggregate volumes is due to a 23.0 million gallon increase resulting from volumes sold by customer services locations added through acquisitions, offset by a 14.5 million gallon decline in volumes sold due in part to warmer weather. We experienced temperatures that were 6.9% warmer than normal and 0.7% warmer than the year ended August 31, 2004. We increased our marketing efforts to attain new customers, which partially offsets the negative factors described above.

•

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

•

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

Analysis of Results of Operations

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

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

Parent Company Only Results

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


	Year Ended
	August 31, 2006			August 31, 2005		Amount of Change
Equity in earnings of affiliates	$	204,987		$	141,260	$	63,727
General and administrative expense		55,374			1,051		54,323
Interest expense		36,773			9,529		27,244
Loss on extinguishment of debt		5,060			—		5,060
Interest and other income (expense), net		(638	)		16,066		(16,704	)

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

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

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

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

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

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

Consolidated Results


	Years Ended
	August 31, 2006			August 31, 2005			Amount of Change
Consolidated Information:
Revenues	$	7,859,096		$	6,168,798		$	1,690,298
Cost of sales		6,568,316			5,381,515			1,186,801

Gross margin		1,290,780			787,283			503,497

Operating expenses		422,989			319,554			103,435
Selling, general and administrative		162,615			64,057			98,558
Depreciation and amortization		129,636			105,751			23,885

Consolidated operating income		575,540			297,921			277,619

Interest expense		(150,646	)		(101,061	)		(49,585	)
Loss on extinguishment of debt		(5,060	)		(6,550	)		1,490
Equity in losses of affiliates		(479	)		(376	)		(103	)
Gain (loss) on disposal of assets		851			(330	)		1,181
Interest and other income, net		13,701			12,191			1,510
Income tax expense		(23,015	)		(4,397	)		(18,618	)
Minority interests		(303,752	)		(96,946	)		(206,806	)

Income from continuing operations		107,140			100,452			6,688
Income from discontinued operations, net of income tax and minority interest expense		—			46,294			(46,294	)

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

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

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

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

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

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

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

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

Income from Discontinued Operations. On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System. For the year ended August 31, 2005, the income from discontinued operations included the gain on sale of the Elk City System of $142.5 million, net of income taxes, and revenues of $105.5 million offset by costs and expenses of $100.0 million and minority interest expense of $101.7 million, resulting in income from discontinued operations of $46.3 million.

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

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

Operating Results by Segment

Midstream Segment


	Years Ended
	August 31, 2006		August 31, 2005		Amount of Change
Revenues	$	4,223,544	$	3,246,772	$	976,772
Cost of sales		4,000,461		3,102,539		897,922

Gross Margin		223,083		144,233		78,850

Operating expenses		31,910		22,835		9,075
Selling, general and administrative		23,922		9,685		14,237
Depreciation and amortization		19,687		17,110		2,577

Segment operating income	$	147,564	$	94,603	$	52,961

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

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

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

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

Transportation and Storage Segment


	Years Ended
	August 31, 2006		August 31, 2005		Amount of Change
Revenues	$	5,013,224	$	2,608,108	$	2,405,116
Cost of sales		4,322,217		2,280,082		2,042,135

Gross Margin		691,007		328,026		362,981

Operating expenses		171,312		113,166		58,146
Selling, general and administrative		46,520		27,021		19,499
Depreciation and amortization		50,755		36,020		14,735

Segment operating income	$	422,420	$	151,819	$	270,601

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

•

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

•

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

•

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

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

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

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

Retail Propane Segment


	Years Ended
	August 31, 2006		August 31, 2005		Amount of Change
Retail propane revenues	$	799,358	$	641,071	$	158,287
Other propane related revenues		80,198		68,402		11,796
Retail propane cost of sales		493,642		384,186		109,456
Other propane related cost of sales		21,776		19,554		2,222

Gross margin		364,138		305,733		58,405

Operating expenses		212,188		176,277		35,911
Selling, general and administrative		17,859		11,067		6,792
Depreciation and amortization		58,036		51,487		6,549

Segment operating income	$	76,055	$	66,902	$	9,153

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

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

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

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

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

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

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

Wholesale Propane Segment


	Years Ended
	August 31, 2006		August 31, 2005			Amount of Change
Revenues	$	94,288	$	68,833		$	25,455
Cost of sales		87,337		64,667			22,670

Gross margin		6,951		4,166			2,785

Operating expenses		3,031		3,139			(108	)
Selling, general and administrative		1,916		1,564			352
Depreciation and amortization		742		754			(12	)

Segment operating income (loss)	$	1,262	$	(1,291	)	$	2,553

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

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

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

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

Other


	Years Ended
	August 31, 2006		August 31, 2005		Amount of Change
Revenue	$	7,740	$	6,867	$	873
Cost of sales		2,139		1,742		397
Operating expenses		4,548		4,137		411
Depreciation and amortization		416		380		36

Other operating income	$	637	$	608	$	29

Unallocated selling, general and administrative expenses	$	72,398	$	14,720	$	57,678

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

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

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

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

Parent Company Only Results


	Year Ended
	August 31, 2005		August 31, 2004		Amount of Change
Equity in earnings of affiliates	$	141,260	$	55,602	$	85,658
Interest expense		9,529		—		9,529
Gain on Energy Transfer Transactions		—		395,253		(395,253	)
Interest and other income, net		16,066		167		15,899

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

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

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

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

Consolidated Results


	Year Ended
	August 31, 2005			August 31, 2004
Revenues	$	6,168,798		$	2,346,957
Cost of sales		5,381,515			1,981,424

Gross margin		787,283			365,533

Operating expenses		319,554			147,374
Selling, general and administrative		64,057			31,111
Depreciation and amortization		105,751			56,242

Consolidated operating income		297,921			130,806

Interest expense		(101,061	)		(41,217	)
Loss on extinguishment of debt		(6,550	)		—
Equity in earnings (losses) of affiliates		(376	)		363
Loss on disposal of assets		(330	)		(1,006	)
Gain on Energy Transfer Transactions		—			395,253
Interest and other income, net		12,191			516
Income tax expense		(4,397	)		(2,792	)
Minority interests		(96,946	)		(35,164	)

Income from continuing operations		100,452			446,759
Income from discontinued operations, net of income tax expense		46,294			3,458

Net income	$	146,746		$	450,217

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

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

Income Tax Expense. Income tax expense was $4.4 million for the year ended August 31, 2005 as compared to $2.8 million for the year ended August 31, 2004. The increase in income tax expense is due to (1) income tax expense recorded in HHI for the entire period in the year ended August 31, 2005 as compared with the year ended August 31, 2004, when tax expense related to HHI was only included in our results of operations after the Energy Transfer Transactions, and (2) increased income from acquisitions, partially offset by lower taxes on the Oasis Pipeline due to lower taxable income for that tax-paying subsidiary.

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

Income from Discontinued Operations. On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191.6 million, including certain adjustments as defined in the purchase and sale agreement. Revenues from the Elk City System were $105.5 million for the period from September 1, 2004 to April 14, 2005 as compared to $135.3 million for the year ended August 31, 2004. Costs and expenses of the Elk City System were $100.0 million for the period from September 1, 2004 to April 14, 2005 and $129.1 million for the year ended August 31, 2004. Income from discontinued operations for the period from September 1, 2004 to April 14, 2005 and for the year ended August 31, 2004 was $5.5 million and $6.2 million, respectively. The decrease in revenues, expenses and income was principally due to the sale occurring in April 2005. The gain on the sale of the Elk City System was $106.1 million, net of related income tax expense of $1.8 million.

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

Operating Results by Segment

Midstream Segment


	Years Ended
	August 31, 2005		August 31, 2004
Revenues	$	3,246,772	$	1,880,663
Cost of sales		3,102,539		1,787,849

Gross Margin		144,233		92,814

Operating expenses		22,835		12,540
Selling, general and administrative		9,685		10,222
Depreciation and amortization		17,110		12,451

Segment operating income	$	94,603	$	57,601

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

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

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

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

Transportation and Storage Segment


	Years Ended
	August 31, 2005		August 31, 2004
Revenues	$	2,608,108	$	113,938
Cost of sales		2,280,082		11,270

Gross Margin		328,026		102,668

Operating expenses		113,166		30,571
Selling, general and administrative		27,021		8,372
Depreciation and amortization		36,020		12,255

Segment operating income	$	151,819	$	51,470

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

•

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

•

ET Fuel System acquisition in June 2004. In connection with the acquisition of the ET Fuel System in June of 2004, we entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115.6 billion Btu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. During the third fiscal quarter of 2005, we were entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above. As a result, we recognized an additional $14.7 million in fees during the third fiscal quarter of 2005. The increase in margin was also due to the Fort Worth Basin expansion completed in May 2005.

•

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

•

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

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

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

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

Retail Propane Segment


	Years Ended
	August 31, 2005		August 31, 2004		August 31, 2004
	(Actual)		(Actual)		(Aggregate)
Retail propane revenues	$	641,071	$	315,177	$	536,636
Other propane related revenues		68,402		34,167		60,646
Retail propane cost of sales		384,186		174,769		296,206
Other propane related cost of sales		19,554		9,602		17,512
Operating expenses		176,277		100,093		158,471
Selling, general and administrative		11,067		6,746		11,080
Depreciation and amortization		51,487		30,925		45,979

Segment operating income	$	66,902	$	27,209	$	68,034

Revenues. For the year ended August 31, 2005, we had retail propane revenues of $641.1 million as compared to retail propane revenues of $315.2 million for the year ended August 31, 2004, due in part to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations. As a comparison, for the year ended August 31, 2004, aggregate retail propane revenues would have been $536.6 million. Of the $104.5 million aggregate increase, $36.3 million is due to the increase in volumes sold by customer service locations added through acquisitions, $91.1 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; offset by a decrease of $22.9 million due to the adverse impact weather had on volumes, as described above. We had other propane related revenues of $68.4 million for the year ended August 31, 2005 compared to $34.2 for the year ended August 31, 2004. As a comparison, aggregate other propane related revenues would have been $60.6 million for the year ended August 31,

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

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

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

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

Depreciation and Amortization. For the year ended August 31, 2005, depreciation and amortization in our retail propane segment was $51.5 million as compared $30.9 million for the year ended August 31, 2004. We would have had aggregate depreciation and amortization of $46.0 million for the year ended August 31, 2004. The aggregate increase of $5.5 million is due primarily to the increase in depreciation of assets and amortization of intangible assets added through acquisitions and the additional depreciation and amortization of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.

Operating Income. For the year ended August 31, 2005, we had retail propane operating income of $66.9 million as compared to retail propane operating income of $27.2 million for the year ended August 31, 2004. Aggregate total operating income for the year ended August 31, 2004 was $68.0 million. These variances are primarily due to changes in revenues and expenses described above.

Wholesale Propane Segment


	Years Ended
	August 31, 2005			August 31, 2004			August 31, 2004
	(Actual)			(Actual)			(Aggregate)
Revenues	$	68,833		$	27,345		$	47,941
Cost of sales		64,667			24,871			43,410
Operating expenses		3,139			1,936			2,912
Selling, general and administrative		1,564			918			1,443
Depreciation and amortization		754			432			626

Segment operating loss	$	(1,291	)	$	(812	)	$	(450	)

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

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

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

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

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

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

Other


	Years Ended
	August 31, 2005		August 31, 2004		August 31, 2004
	(Actual)		(Actual)		(Aggregate)
Revenue	$	6,867	$	3,465	$	5,283
Cost of sales		1,742		861		1,304
Operating expenses		4,137		2,234		3,614
Depreciation and amortization		380		179		321

Other operating income	$	608	$	191	$	44

Unallocated selling, general and administrative expenses	$	14,720	$	4,853	$	10,095

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

Income Taxes

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

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


	Year Ended August 31,
	2006		2005		2004
Federal statutory tax rate	35.00	%	35.00	%	35.00	%
State income tax rate net of federal benefit	3.10	%	3.56	%	3.96	%
Earnings not subject to tax at the Partnership level	(32.80	)%	(36.58	)%	(38.39	)%

Effective tax rate	5.30	%	1.98	%	0.57	%

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


	Year Ended August 31,
	2006			2005			2004
Current income tax expense:
Federal	$	27,640		$	5,042		$	6,505
State		1,987			963			830
Deferred income tax expense (benefit):
Federal		(6,227	)		(2,015	)		(4,366	)
State		(385	)		407			(177	)

Total income tax expense before gain on discontinued operations		23,015			4,397			2,792

Gain on discontinued operations:
Current income tax expense:
Federal		—			1,570			—
State		—			259			—

		—			1,829			—

Total income tax expense	$	23,015		$	6,226		$	2,792

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

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

Liquidity and Capital Resources

Parent Company Only

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

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

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

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

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

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

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

ETP

ETP’s ability to satisfy its obligations and pay distributions to its partners will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

ETP’s future capital requirements will generally consist of:

•

maintenance capital expenditures, which include capital expenditures made to connect additional wells to its natural gas systems in order to maintain or increase throughput on existing assets for which it expects to expend $38.3 million in the next fiscal year and capital expenditures to extend the useful lives of its propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet for which ETP expects to expend $22.7 million in the next fiscal year;

•

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

•

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

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

•

maintenance capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable;

•

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

•

acquisition capital expenditures will be financed by the proceeds of borrowings under the existing ETP credit facilities, other ETP lines of credit, long-term debt, the issuance of additional Common Units or a combination thereof.

The assets utilized in ETP’s propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its propane business. In addition, ETP does not experience any significant increases attributable to inflation in the cost of these assets or in its propane operations. The assets used in ETP’s midstream and transportation and storage segments, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than those expenditures necessary to maintain the service capacity of ETP’s existing assets.

In connection with the HPL acquisition, ETP engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although ETP intends to fund natural gas purchases with cash generated from operations, from time to time it may need to finance the purchase of natural gas to be held in storage with borrowings from its current credit facilities. ETP intends to repay these borrowings with cash generated from operations when the gas is sold.

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

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

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, including the recently acquired Titan operations, and other factors.

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

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

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

Financing and Sources of Liquidity

Description of Indebtedness

Our indebtedness as of August 31, 2006 consists of the Parent Company’s Senior Secured Credit Agreement which includes a $500.0 million Senior Secured Revolving Credit Facility available through February 8, 2011, and a $150.0 million Senior Secured Term Loan Facility due February 8, 2012. ETP has $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012, a Revolving Credit Facility that allows for borrowings of up to $1.3 billion, expanded to $1.5 billion subsequent to August 31, 2006, available through June 29, 2011, and a $200.0 million Revolving Credit Facility that matures on December 1, 2006 (paid and canceled subsequent to August 31, 2006). We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our subsidiaries are described in more detail below and in

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

Parent Company Indebtedness

Senior Secured Credit Agreement

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

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

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility and the Senior Secured Term Loan Facility bear interest at the Parent Company’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio. The weighted average interest rate was 6.76% for the amount outstanding on the Parent Company Revolving Credit Facility and 7.5% on the Senior Secured Term Loan Facility as of August 31, 2006.

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

2005 Senior Secured Term Loan Agreement

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

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

Energy Transfer Partners Indebtedness

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

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

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

2005 Senior Notes

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

The Senior Notes represent ETP’s senior unsecured obligations and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. The Senior Notes are jointly and severally guaranteed by ETC OLP and all of the direct and indirect wholly and majority-owned subsidiaries of ETC OLP. The subsidiary guarantees rank equally in right of payment with all of the existing and future unsubordinated indebtedness of ETP’s guarantor subsidiaries. The Senior Notes and each guarantee will effectively rank junior to any future indebtedness of ours or our subsidiary guarantors that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the Senior Notes will effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries that are not subsidiary guarantors.

The Senior Notes were issued under an indenture containing covenants, which include covenants that restrict our ability to, subject to certain exceptions, incur debt secured by liens, engage in sale and leaseback transactions or merge or consolidate with another entity or sell substantially all of our assts.

HOLP Senior Secured Notes

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

Revolving Credit Facilities

ETP Facilities

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

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

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

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

HOLP Facilities

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

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

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

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

Debt Covenants

The agreements for each of the Senior Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The most restrictive of these covenants require ETP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The HOLP debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the Note Agreements could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of August 31, 2006.

Contractual Obligations

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


In thousands	Payments Due by Period
Contractual Obligations	Total		Less Than 1 Year		1–3 Years		3–5 Years		More Than 5 Years
Long-term debt	$	3,246,253	$	40,607	$	90,928	$	1,723,131	$	1,391,587
Interest on fixed rate long-term debt (a)		614,499		90,145		170,029		155,581		198,744
Payments on derivatives		38,646		36,918		1,728		—		—
Purchase commitments (b)		482,300		482,300		—		—		—
Operating lease obligations		49,178		8,809		16,946		13,789		9,634

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

(a)

Fixed rate interest on long-term debt includes the amount of interest due on our fixed rate long-term debt. These amounts do not include interest on our variable rate debt obligations which include our Revolving Credit Facilities and, Revolving Credit Facility Swingline Loan options. As of August 31, 2006, variable rate interest on our outstanding balance of variable rate debt of $1.8 billion would be $115.3 million on an annual basis. See Note 6 – “Debt Obligations” to the consolidated financial statements beginning in Item 8 of this report for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt.

(b)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We

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

Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

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


	Record Date	Payment Date	Amount per Unit
Fiscal Year 2006
	March 31, 2006	April 19, 2006	$	0.0578
	June 30, 2006	July 19, 2006	$	0.2375

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

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


	2006		2005		2004
Limited Partners -
Limited Partners (a)	$	34,010	$	666,751	$	263,774
Common Units		65,905		—		—
Class B Units		745		—		—
General Partner		599		4,861		2,503

Total distributions declared	$	101,259	$	671,612	$	266,277

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

Cash Distributions Received by the Parent Company

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

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


	2006			2005			2004
Limited Partners Interests	$	80,203		$	57,671		$	20,411
General Partner Interest		6,931			4,237			1,059
Incentive Distribution Rights		64,436			27,971			2,890
Less holdbacks (a)		(2,287	)		(8,182	)		—

Total distributions received from ETP	$	149,283		$	81,697		$	24,360

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

Cash Distributions Paid by ETP

ETP will use its cash provided by operating and financing activities from the Operating Partnerships to provide distributions to its Unitholders. Under ETP’s Partnership Agreement, ETP will distribute to its partners within 45 days after the end of each fiscal quarter, an amount equal to all of its Available Cash for such quarter. Available Cash generally means, with respect to any quarter of ETP, all cash on hand at the end of such quarter less the amount of cash reserves established by ETP’s General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. ETP’s commitment to its Unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for its operations. Heritage (the predecessor to ETP) paid all quarterly distributions since its inception in 1996 up to and including the quarterly distribution of $0.325 per unit paid on January 14, 2004. Heritage had raised its quarterly distribution over the years from $0.25 per unit in 1996 to $0.325 per unit as of the quarterly distribution paid on January 14, 2004.

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


	Record Date	Payment Date	Amount per Unit
Fiscal Year 2006
	September 30, 2005	October 14, 2005	$	0.5000
	January 4, 2006	January 13, 2006	$	0.5500
	March 24, 2006	April 14, 2006	$	0.5875
	June 30, 2006	July 14, 2006	$	0.6375
	June 30, 2006 (1)	July 14, 2006	$	0.0325
Fiscal Year 2005
	October 7, 2004	October 15, 2004	$	0.4125
	January 5, 2005	January 14, 2005	$	0.4375
	March 16, 2005	April 14, 2005	$	0.4625
	July 8, 2005	July 14, 2005	$	0.4875
Fiscal Year 2004
	April 2, 2004	April 14, 2004	$	0.3500
	July 2, 2004	July 15, 2004	$	0.3750

(1)

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

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

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


	2006		2005		2004
Limited Partners -
Common Units	$	248,237	$	173,802	$	52,963
Class D Units		—		—		5,405
Class C Units (1)		3,599		—		—
Class F Units		3,232		—		—

General Partner -
2% Ownership		6,981		4,390		1,392
Incentive Distribution Rights		81,722		28,847		3,623

Total distributions declared	$	343,771	$	207,039	$	63,383

(1)	Special SCANA distribution – see discussion above.

New Accounting Standards

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

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

SFAS No. 154, Accounting Changes and Error Correction – a replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Management will adopt the provisions of SFAS 154 beginning September 1, 2006, as applicable. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.

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

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

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

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

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

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Note 3 – “Significant Accounting Policies and Balance Sheet Detail” to our consolidated financial statements in this report.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. As is normal in the natural gas industry, our most current month’s financial results for our midstream and transportation and storage segments are estimated using volume estimates and market prices. Actual results could differ from our estimates if the underlying assumptions prove to be incorrect.

Revenue Recognition. Revenues for sales of natural gas, NGLs including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor, transportation, treating, compression, and gas processing, is recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Tank rent is recognized ratably over the period it is earned.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount, or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and processes natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

Our transportation and storage segment results are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. The transportation and storage segment also generates its revenues and margin from the sale and marketing of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL system.

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

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

of products sold in the consolidated statement of operations. On our contracts that are designated as cash flow hedges in accordance with SFAS No. 133, the effective portion of the hedged gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the physical transaction settles. The ineffective portion of the gain or loss is reported in earnings immediately. We utilize published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. We also use the Black-Scholes valuation model to estimate the value of certain options. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.

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

Volume Measurement. We record amounts for natural gas gathering and transportation revenue, liquid transportation and handling revenue, natural gas sales and natural gas purchases, and the sale of production based on volumetric calculations. Variances resulting from such calculations are inherent in our business.

Impairment of Long-Lived Assets and Goodwill. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

In order to test for recoverability, we must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas and propane supply, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other midstream companies, including major energy producers. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.

Property, Plant, and Equipment. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures also include capital expenditures made to connect additional wells to our systems in order to maintain or increase throughput on our existing assets. Growth or expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful life ranging from 5 to 65 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful live of our property, plant, and equipment.

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

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

In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective. We have determined that we are obligated by contractual or regulatory requirements to remove assets or perform other remediation upon retirement of certain assets. However, the fair value of our asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. We will record an asset retirement obligation in the periods in which it can reasonably determine the settlement dates.

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

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

Non-trading Activities

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when 1) sales volumes are less than expected, or 2) our counterparties fail to purchase the contracted quantities of natural gas or propane or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly protected against decreases in such prices on hedged transactions.

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

In connection with the acquisition of HPL, we acquired certain physical forward contracts that contain embedded options that we have not designated as a normal purchase and sale nor were the contracts designated as hedges under SFAS 133. These contracts are marked to market, along with the financial options that offset them, and are recorded in the statement of operations and on our consolidated balance sheet as a component of price risk management assets and liabilities.

In our midstream and transportation and storage segments, we account for certain of our derivatives as cash flow hedges under SFAS 133. All derivatives are recognized on the balance sheet at fair value as price risk management assets and liabilities. The changes in the fair value of price risk management assets and liabilities that are designated, documented as cash flow hedges, and determined to be effective are recorded through other comprehensive income (loss). The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income (loss) and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. For those derivatives that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations.

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

Trading Activities

We have a risk management policy that provides for our marketing and trading operations to execute limited strategies. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis and gas daily contracts. These instruments are within the guidelines of the risk management policy which has been approved by our Board of Directors. The trading activities are a compliment to the producer services’ operations and are accounted for in net revenues on the consolidated statement of operations. We follow the applicable provisions of EITF Issue 02-3 which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the consolidated statement of operations as other revenue. Changes in the assets and liabilities from the trading activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. Forward physical contracts associated with the trading activities are marked to market and included in revenue on our consolidated statement of operations because they do not meet “normal purchases and sales exception” of SFAS 133.

Commodity-related Derivatives

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


	Commodity	Notional Volume MMBTU	Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	33,711,140	2006-2009	$	(6,247	)
Swing Swaps IFERC	Gas	(37,220,448)	2006-2008		2,618
Fixed Swaps/Futures	Gas	3,607,500	2006-2007		(170	)
Forward Physical Contracts	Gas	(7,986,000)	2006-2008		(21,653	)
Options	Gas	(1,046,000)	2006-2008		21,653
Forwards/Swaps (in Gallons)	Propane	24,066,000	2006-2007		199

(Trading)
Basis Swaps IFERC/NYMEX	Gas	(2,572,500)	2006-2008		21,995
Swing Swaps IFERC	Gas	—	2006		(31	)
Forward Physical Contracts	Gas	(455,000)	2006		(68	)

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,585,000)	2006-2007		(2,987	)
Fixed Swaps/Futures	Gas	(37,872,500)	2006-2007		2,043

Credit Risk

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

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

Sensitivity analysis

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


	Notional Volume MMBTU		Fair Value			Effect of Hypothetical 10% Change
Non-Trading Derivatives
Fixed Swaps/Futures	(34,265,000	)	$	1,873		$	42,615
Basis Swaps IFERC/NYMEX	(873,860	)		(9,234	)		1,594
Swing Swaps IFERC	(37,220,448	)		2,618			514
Options	(1,046,000	)		21,653			5,189
Forward Physical Contracts	(7,986,000	)		(21,653	)		5,189
Propane Forwards/Swaps (in Gallons)	24,066,000			199			2,766

Trading Derivatives
Swing Swaps IFERC	—			(31	)		205
Basis Swaps IFERC/NYMEX	(2,572,500	)		21,995			701
Forward Physical Contracts	(455,000	)		(68	)		75

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


	Notional Volume MMBTU		Fair Value			Effect of Hypothetical 10% Change
Nymex Futures/ Fixed Price	(43,937,500	)	$	(148,006	)	$	51,962
Basis Swaps	(96,846,114	)		53,840			9,788
Fixed Price Index Swaps	5,910,000			36,455			6,472
Options	(1,776,000	)		78,941			16,034
Swing Swaps	(67,841,503	)		(10,085	)		1,428
Forward Contracts	(21,340,000	)		(78,500	)		16,034

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

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

Interest Rate Risk

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

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

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

We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries


		Page
Report of Independent Registered Public Accounting Firm		83

Consolidated Balance Sheets – August 31, 2006 and 2005		84

Consolidated Statements of Operations – Years Ended August 31, 2006, 2005, and 2004		86

Consolidated Statements of Comprehensive Income (Loss) – Years Ended August 31, 2006, 2005, and 2004		87

Consolidated Statements of Partners’ Capital (Deficit) – Years Ended August 31, 2006, 2005, and 2004		88

Consolidated Statements of Cash Flows – Years Ended August 31, 2006, 2005, and 2004		89

Notes to Consolidated Financial Statements		90

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Energy Transfer Equity, L.P.

We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries, as of August 31, 2006 and 2005 and the related consolidated statements of operations, comprehensive income, partners’ capital (deficit), and cash flows for each of the three years in the period ended August 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of August 31, 2006 and 2005 and the results of their operations and their cash flows for each of the three years in the period ended August 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)


	August 31, 2006		August 31, 2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	26,204	$	33,459
Marketable securities		2,817		3,452
Accounts receivable, net of allowance for doubtful accounts		675,545		847,028
Accounts receivable from related companies		602		2,295
Inventories		387,140		291,445
Deposits paid to vendors		87,806		65,034
Exchanges receivable		23,221		35,623
Price risk management assets		56,851		138,961
Prepaid expenses and other		42,549		36,433

Total current assets		1,302,735		1,453,730

PROPERTY, PLANT AND EQUIPMENT, net		3,748,614		2,887,750
LONG-TERM PRICE RISK MANAGEMENT ASSETS		2,192		41,687
ADVANCES TO AND INVESTMENT IN AFFILIATES		41,344		37,353
GOODWILL		633,998		353,608
INTANGIBLES AND OTHER ASSETS, net		185,735		118,091
OTHER LONG-TERM ASSETS		9,523		13,453

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

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)


	August 31, 2006			August 31, 2005
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

CURRENT LIABILITIES:
Working capital facility	$	—		$	17,026
Accounts payable		603,527			818,810
Accounts payable to related companies		320			410
Exchanges payable		24,722			33,772
Customer advances and deposits		108,836			138,442
Accrued and other current liabilities		205,228			90,114
Price risk management liabilities		36,918			104,772
Income taxes payable		—			2,063
Deferred income taxes		629			—
Current maturities of long-term debt		40,607			39,376

Total current liabilities		1,020,787			1,244,785
LONG-TERM DEBT, less current maturities		3,205,646			2,275,965
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		2,843			30,517
LONG-TERM PAYABLE TO AFFILIATE		—			2,005
DEFERRED INCOME TAXES		207,877			215,118
OTHER NON-CURRENT LIABILITIES		2,110			13,284
MINORITY INTERESTS		1,439,127			1,212,135

COMMITMENTS AND CONTINGENCIES (Note 10)

Total liabilities		5,878,390			4,993,809

PARTNERS’ CAPITAL (DEFICIT):
General Partner		(69	)		772
Limited Partners -
Common Unitholders (124,360,520 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)		(9,586	)		—
Class B Unitholders (2,521,570 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)		53,130			—
Limited partners’ deficit (0 and 136,357,870 limited partner units issued and outstanding at August 31, 2006 and 2005, respectively)		—			(62,216	)

		43,475			(61,444	)
Accumulated other comprehensive income (loss)		2,276			(26,693	)

Total partners’ capital (deficit)		45,751			(88,137	)

Total liabilities and partners’ capital (deficit)	$	5,924,141		$	4,905,672

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
REVENUES:
Midstream and transportation and storage	$	6,877,512		$	5,383,625		$	1,966,803
Propane		893,647			709,904			342,523
Other		87,937			75,269			37,631

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

COSTS AND EXPENSES:
Cost of products sold – midstream and transportation and storage		5,963,422			4,911,366			1,771,321
Cost of products sold – propane		580,978			448,853			199,640
Cost of products sold – other		23,916			21,296			10,463
Operating expenses		422,989			319,554			147,374
Depreciation and amortization		129,636			105,751			56,242
Selling, general and administrative		162,615			64,057			31,111

Total costs and expenses		7,283,556			5,870,877			2,216,151

OPERATING INCOME		575,540			297,921			130,806

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(150,646	)		(101,061	)		(41,217	)
Loss on extinguishment of debt		(5,060	)		(6,550	)		—
Equity in earnings (losses) of affiliates		(479	)		(376	)		363
Gain (loss) on disposal of assets		851			(330	)		(1,006	)
Gain on Energy Transfer Transactions		—			—			395,253
Interest and other income, net		13,701			12,191			516

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		433,907			201,795			484,715

Income tax expense		(23,015	)		(4,397	)		(2,792	)

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		410,892			197,398			481,923
Minority interests		(303,752	)		(96,946	)		(35,164	)

INCOME FROM CONTINUING OPERATIONS		107,140			100,452			446,759

DISCONTINUED OPERATIONS:
Income from discontinued operations		—			5,498			6,163
Gain on sale of discontinued operations, net of income tax expense		—			106,092			—
Minority interest in income from discontinued operations		—			(65,296	)		(2,705	)

Total income from discontinued operations		—			46,294			3,458

NET INCOME		107,140			146,746			450,217
GENERAL PARTNER’S INTEREST IN NET INCOME		609			1,207			4,438

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	106,531		$	145,539		$	445,779

BASIC NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.80		$	0.89		$	4.54
Limited Partners’ income from discontinued operations		—			0.41			0.04

NET INCOME PER LIMITED PARTNER UNIT	$	0.80		$	1.30		$	4.58

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		133,820,176			111,939,537			97,474,988

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.79		$	0.75		$	3.35
Limited Partners’ income from discontinued operations		—			0.34			0.03

NET INCOME PER LIMITED PARTNER UNIT	$	0.79		$	1.09		$	3.38

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		133,820,176			132,795,472			131,923,251

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	For the Year Ended August 31, 2006			For the Year Ended August 31, 2005			For the Year Ended August 31, 2004
NET INCOME	$	107,140		$	146,746		$	450,217

OTHER COMPREHENSIVE INCOME BEFORE TAX:

Reclassification adjustment for gains and losses on derivative instruments accounted for as hedged included in net income before tax benefits of $91, $0, and $0 for years ended August 31, 2006, 2005 and 2004, respectively.		(74,598	)		25,280			(3,396	)
Change in value of derivative instruments accounted for as hedges, before tax expense of $(204), $0, and $0 for the years ended August 31, 2006, 2005, and 2004, respectively.		167,729			(111,617	)		3,481
Change in value of available-for-sale securities, before tax benefit of $1, $0, and $0 for the years ended August 31, 2006, 2005, and 2004, respectively.		(635	)		988			(53	)
Income tax expense related to items of other comprehensive income		(112	)		—			—
Minority interests		(63,415	)		58,645			(21	)

Comprehensive income	$	136,109		$	120,042		$	450,228

Reconciliation of Accumulated Other Comprehensive Income (Loss)

Balance, beginning of period	$	(26,693	)	$	11		$	—

Current period reclassification to earnings		(74,507	)		25,280			(3,396	)
Current period change		166,891			(110,629	)		3,428
Minority interests		(63,415	)		58,645			(21	)

Balance, end of period	$	2,276		$	(26,693	)	$	11

Components of Accumulated Other Comprehensive Income (Loss)

Other comprehensive income (loss) related to:
Commodity-related derivative hedges net of tax expense of $203, $0 and $0 for the years ended August 31, 2006, 2005 and 2004, respectively	$	2,095		$	(84,523	)	$	85
Interest rate derivative hedges net of tax benefit of $90, $0 and $0 for the years ended August 31, 2006, 2005 and 2004, respectively		4,672			(1,729	)		—
Available-for-sale securities net of tax benefit of $1, $0 and $0 for for the years ended August 31, 2006, 2005 and 2004, respectively		300			935			(53	)
Minority interests		(4,791	)		58,624			(21	)

Balance, end of period	$	2,276		$	(26,693	)	$	11

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)

(in thousands)


	General Partner			Common Unitholders			Class B Unitholders			Limited Partners
Balance, August 31, 2003	$	2,118		$	—		$	—		$	180,513
Units issued in exchange for property and subsidiary interests		—			—			—			1,743
Distributions to partners		(2,503	)		—			—			(263,774	)
Net income		4,438			—			—			445,779

Balance, August 31, 2004		4,053			—			—			364,261
Retirement of limited partner interests		—			—			—			(20,333	)
Distributions to partners		(4,861	)		—			—			(666,751	)
Issuance of additional limited partner interests		—			—			—			55,884
Capital transaction on sale of subsidiary Common Units		373			—			—			59,184
Net income		1,207			—			—			145,539

Balance, August 31, 2005		772			—			—			(62,216	)
Units issued in IPO, net of issuance costs		—			473,978			—			—
Distribution of interest in ETP GP, LP		(27	)		(4,428	)		—			—
Conversion to Common Units		—			(39,606	)		—			39,606
Redemption of Common Units		(824	)		(130,796	)		—			—
Repurchase of Common Units		—			(237,817	)		—			—
Distributions to partners		(599	)		(65,905	)		(745	)		(34,010	)
Purchase premium on ETP shares		—			(54,001	)		—			—
Compensation expense on issuance of Class B Units		—			—			52,953			—
Net income		609			48,989			922			56,620

Balance, August 31, 2006	$	(69	)	$	(9,586	)	$	53,130		$	—

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	107,140		$	146,746		$	450,217
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization related to continuing and discontinued operations		129,636			107,298			58,491
Amortization of deferred finance costs charged to interest expense		3,959			4,399			2,642
Loss on extinguishment of debt		5,060			6,550			—
Provision for bad debts		1,723			5,523			1,667
(Gain) loss on disposal of assets		(851	)		330			1,006
Gain on retirement of limited partner interests		—			(11,166	)		—
Gain on sale of discontinued operations before income tax expense		—			(110,024	)		—
Gain on Energy Transfer Transactions		—			—			(395,253	)
Unit-based compensation and long-term incentive plan		59,991			1,608			42
Undistributed losses (earnings) affiliates and other		(378	)		526			(171	)
Deferred income tax benefit		(6,724	)		(1,609	)		(5,413	)
Minority interests		303,752			162,242			37,869
Distributions from subsidiary to minority unitholders		(192,146	)		(117,139	)		(39,388	)
Net change in operating assets and liabilities, net of acquisitions		(100,380	)		(157,151	)		10,389

Net cash provided by operating activities		310,782			38,133			122,098

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(586,185	)		(1,131,844	)		(622,929	)
Working capital settlement on prior year acquisitions		19,653			—			—
Capital expenditures		(680,164	)		(196,459	)		(109,688	)
Proceeds from the sale of discontinued operations		—			191,606			—
Proceeds from sale of investment in affiliates		—			2,632			—
Advances to and investment in affiliates		(4,651	)		(2,355	)		(322	)
Proceeds from the sale of assets		6,941			5,303			1,108

Net cash used in investing activities		(1,244,406	)		(1,131,117	)		(731,831	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		3,495,806			3,769,721			894,079
Principal payments on debt		(2,567,053	)		(2,538,209	)		(510,182	)
Equity offering		473,978			—			—
Redemption of Common Units		(131,620	)		—			—
Repurchase of Common Units		(237,817	)		—			—
Equity offering of subsidiary		—			507,724			528,129
Cash distributions to Partners		(101,259	)		(671,612	)		(266,277	)
Debt issuance costs		(5,666	)		(22,987	)		(8,236	)
Retirement of employee incentive units		—			(1,046	)		—

Net cash provided by financing activities		926,369			1,043,591			637,513

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(7,255	)		(49,393	)		27,780

CASH AND CASH EQUIVALENTS, beginning of period		33,459			82,852			55,072

CASH AND CASH EQUIVALENTS, end of period	$	26,204		$	33,459		$	82,852

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

1.	OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The accompanying consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries (“the Partnership”, “ETE” or the “Parent Company”) presented herein for the years ended August 31, 2006, 2005 and 2004, have been prepared in accordance with accounting principles generally accepted in the United States of America and pursuant to the rules and regulations of the Securities and Exchange Commission. We consolidate all majority-owned subsidiaries and limited partnerships which we control as the general partner or owner of the general partner. We recognize a minority interest liability and minority interest expense for all partially-owned consolidated subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation.

The consolidated financial statements of the Partnership presented herein for the year ended August 31, 2006 include the results of operations of ETE and ETE’s controlled subsidiaries: Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), Energy Transfer Partners GP, L.P., the General Partner of ETP (“ETP GP”), and ETE’s wholly-owned subsidiary, Energy Transfer Partners, L.L.C., the General Partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (referenced herein as “HOLP”) and Heritage Holdings, Inc. (“HHI”) for the entire period from September 1, 2005 through August 31, 2006. The results of operations for Titan Energy Partners, L.P. (“Titan”) are included since the date of acquisition (June 1, 2006).

The consolidated financial statements of the Partnership presented herein for the year ended August 31, 2005 include the results of operations for ETC OLP, HOLP and HHI for the entire period from September 1, 2004 through August 31, 2005 and the Houston Pipeline System (“HPL”) since the date of acquisition (January 26, 2005).

The financial statement information presented for the year ended August 31, 2004 includes the results of operations for ETC OLP for the entire period from September 1, 2003 to August 31, 2004. However, the results of operations for HOLP and HHI are only included from the date of the Energy Transfer Transactions (January 20, 2004) to August 31, 2004 (see Note 2). In addition, on June 2, 2004, ETC OLP acquired the TUFCO System (now referred to as the ET Fuel System) from TXU Fuel Company, a subsidiary of TXU Corp. The accompanying financial statements include the results of operations of the ET Fuel System beginning June 2, 2004, and the Bossier Pipeline (now known as the East Texas Pipeline) since June 21, 2004. The comparability of the accompanying consolidated financial statements is also affected by other acquisitions and the disposition of ETC Oklahoma Pipeline, Ltd. (“Elk City”) as described in Note 2, and various transactions which occurred in conjunction with ETE’s initial public offering (“IPO”) as described in Note 7.

We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

Certain prior period amounts have been reclassified to conform with the 2006 presentation. These reclassifications had no impact on net income or total partners’ capital.

Business Operations

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we operate, our activities are conducted through three subsidiary operating partnerships, ETC OLP, a Texas limited partnership engaged in midstream and transportation and storage natural gas operations, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations (collectively the “Operating Partnerships”). The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “ETP” or the “Partnership.”

ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, natural gas intrastate pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (“NGLs”) in the states of Texas, Louisiana and, formerly, Oklahoma. ETC OLP was owned 99.9% by ETP subsequent to the Energy Transfer Transactions and 0.1% by ETC OLP’s General Partner, LA GP, LLC, a wholly-owned subsidiary of ETP. ETC OLP was contributed to Heritage on January 19, 2004, and became a wholly-owned subsidiary of ETP.

As of August 31, 2006, ETC OLP owns an interest in and operates approximately 12,000 miles of natural gas gathering and transportation pipelines with an additional 600 miles under construction, three natural gas processing plants, two of which are currently connected to its gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities.

Our midstream segment focuses on gathering, compression, treating, blending, processing and marketing of natural gas. Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas.

Our transportation and storage segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through the Oasis Pipeline, the East Texas Pipeline, the Fort Worth Basin Pipeline, the natural gas pipeline and storage assets that are referred to as the ET Fuel System, and the natural gas pipeline and storage assets of the HPL System.

Our propane segments consist of HOLP and Titan which collectively sell propane and propane-related products to more than 1,000,000 active residential, commercial, industrial, and agricultural customers from 442 customer locations in 41 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership, a Canadian partnership, in which we own a 60% interest, engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

The Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited and General Partner interests in ETP.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETP and its consolidated subsidiaries. In order to fully understand the financial condition of the Partnership on a stand-alone basis, see Note 16 for stand-alone financial information apart from that of the consolidated partnership information included herein.

2.	SIGNIFICANT ACQUISITIONS AND DISPOSITIONS:

Significant Acquisitions:

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (now known as Energy Transfer Equity, L.P. (“ETE”)) completed the series of transactions whereby ETE contributed ETC OLP to Heritage in exchange for cash, Common Units, Class D Units and Special Units of Heritage. Simultaneously, ETE acquired the General Partner of Heritage, Energy Transfer Partners GP, L.P. (formerly U.S. Propane, L.P.) and Energy Transfer Partners, L.L.C. (formerly U.S. Propane, L.L.C.) from their owners, and coupled with the Heritage Limited Partner interests ETE received, thereby gained control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) from the owners of Energy Transfer Partners GP, L.P.

Subsequent to the Energy Transfer Transactions, Heritage changed its name to Energy Transfer Partners, L.P., and began trading on the New York Stock Exchange under the ticker symbol “ETP”. The name change and new ticker symbol were effective March 1, 2004.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standard No. 141, Business Combinations (“SFAS 141”). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquirer for accounting purposes. As a result, ETC OLP’s historical financial statements are now the historical financial statements of ETP. Consequently, the accompanying financial statements do not reflect 100% of the results of Heritage as those results prior to January 19, 2004 (the date of the Energy Transfer Transactions) are not included. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. In accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141, the assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by ETE through its acquisition of the General Partner and approximately 35.4% of the limited partner interests of Heritage. The assets and liabilities of ETC OLP have been recorded at historical cost. Although the partners’ capital accounts of ETC OLP became the capital accounts of Heritage, Heritage’s partnership structure and partnership units survive.

The acquisition of HHI by Heritage was accounted for as a capital transaction as the primary asset held by HHI was 8,853,832 Common Units of ETP on a post-split basis following the two-for-one split completed on March 15, 2005. Concurrent with the acquisition of HHI by Heritage, these Common Units were converted to ETP Class E Units.

ETE received ETP Special Units in the Energy Transfer Transactions as consideration for the East Texas Pipeline project which was in progress at that time. Upon completion of the East Texas Pipeline in June 2004, the Special Units, which initially had no value assigned, were converted to Common Units, which resulted in additional consideration being recorded. The additional consideration adjusted the percent of Heritage acquired to 41.5% and resulted in an additional fair value step-up to Heritage’s assets of approximately $38,000 as determined in accordance with EITF 90-13.

The excess purchase price over Heritage’s cost was determined as follows:


Net book value of Heritage at January 20, 2004	$	239,102
Historical goodwill at January 20, 2004		(170,500	)
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		267,210
Percent of Heritage acquired by La Grange Energy		41.5	%

Equity interest acquired	$	110,892

Fair market value of Limited Partner Units	$	668,534
Purchase price of General Partner Interest		30,000
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		897,142
Percent of Heritage acquired by La Grange Energy		41.5	%

Fair value of equity acquired		372,314
Net book value of equity acquired		110,892

Excess purchase price over Heritage cost	$	261,422

The excess purchase price over Heritage cost was allocated as follows:


Property, plant and equipment (25 year life)	$	35,269
Customer lists (15 year life)		18,926
Trademarks		19,251
Goodwill		187,976

	$	261,422

Management obtained an independent valuation and made the final modifications to the purchase price during the first quarter of fiscal year 2005.

The gain recognized by ETE as a result of the Energy Transfer Transactions was determined as follows:


ETE’s historical basis in ETC OLP	$	(90,906	)
Percent sold in Energy Transfer Transactions		58.5	%

		(53,180	)

Fair value of Heritage equity acquired in Energy Transfer Transactions		372,314
Less: Consideration paid for ETP’s GP interest		(30,000	)

Fair value of assets received in Energy Transfer Transactions		342,314

Gain on partial sale of ETC OLP	$	395,494

The assets and liabilities of ETC OLP were stepped up to fair value to the extent sold by ETE approximately 58.5% in the Energy Transfer Transactions determined in accordance with EITF 90-13 and SFAS 141. The step up resulted in an approximate $504,000 increase to property, plant and equipment at ETE, which is being depreciated over estimated lives 5 to 65 years. Deferred taxes were calculated on $201.5 million of the step-up of the assets which were attributable to a taxable subsidiary of ETC OLP, resulting in approximately $108.5 million of deferred tax liabilities recorded by ETE. The deferred tax liabilities will reverse at the same rate as the related step-up in assets will be depreciated.

Goodwill of $29,589 was recorded in connection with ETE’s acquisition of ETP GP. Goodwill was warranted because, as the General Partner of ETP, ETP GP owns certain incentive distribution rights, which entitle it to receive distributions in excess of its 2% general partner interest in ETP.

Fiscal year 2006 acquisitions

On November 10, 2005, we acquired the remaining 2% limited partnership interests in HPL for $16,560 in cash. The purchase price was allocated to property, plant and equipment and the minority interest liability associated with the 2% limited partner interests was eliminated. As a result, HPL became a wholly-owned subsidiary of ETC OLP. We also reached a settlement agreement with AEP in November 2005 related to certain inventory and working capital matters associated with the acquisition. The terms of the agreement were not material in relation to our financial position or results of operations.

operating territories in which we did not previously have operations. This expansion will further reduce the impact on the propane operations from weather patterns in any one area of the U.S., while continuing our focus on conducting the retail propane operations in attractive high-growth areas. We accounted for the Titan acquisition as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141. The purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition based on the preliminary results of an independent appraisal. We expect to complete the purchase allocation during our first or second quarter of fiscal year 2007 upon the completion of the independent appraisal. Pro forma results of operations due to the Titan acquisition are discussed below.

During the fiscal year ended August 31, 2006, HOLP and Titan collectively acquired substantially all of the assets of eight propane businesses. The aggregate purchase price for these acquisitions totaled $28,902 which included $20,572 of cash paid, net of cash acquired, 99,955 ETP Common Units issued valued at $4,000 and liabilities assumed of $4,327. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for these fiscal year 2006 acquisitions:


	Titan June 2006			Midstream and Transportation and Storage Acquisitions			Propane-related Acquisitions (Aggregated)
Cash and equivalents	$	24,458		$	—		$	3
Accounts receivable		20,304			396			1,702
Inventory		11,417			20			795
Prepaid and other current assets		2,055			4			83
Investments in unconsolidated affiliate		—			(50	)		—
Price risk management assets		720			—			—
Property, plant, and equipment		202,598			308			19,276
Intangibles and other assets		74,532			—			5,342
Goodwill		278,149			—			1,701
Other long-term assets		5,055			—			—

Total assets acquired		619,288			678			28,902

Accounts payable		(18,337	)		(211	)		—
Accrued expenses		(14,992	)		(10	)		(1,748	)
Customer advances and deposits		(11,356	)		—			—
Other current liabilities		—			—			—
Current maturities of long term debt		(964	)		—			—
Long-term debt		(692	)		—			(2,579	)
Minority interest		—			16,667			—

Total liabilities assumed		(46,341	)		16,446			(4,327	)

Net assets acquired	$	572,947		$	17,124		$	24,575

We recorded the following intangible assets in conjunction with these acquisitions:


Customer lists (3-15 years)	$	37,333
Non-compete agreements (5 to 10 years)		2,315
Software		2,200

Total amortized intangible assets		41,848
Trademarks and trade names		35,395
Goodwill		279,850
Other assets		2,631

Total intangible assets and goodwill acquired	$	359,724

Goodwill was warranted because these acquisitions enhance our current operations and certain acquisitions are expected to reduce costs through synergies with existing operations. We expect all of the goodwill acquired to be tax deductible.

We obtained the final independent valuation for the fiscal year 2005 HPL acquisition (as discussed below) and made the final allocations of the purchase price to the acquired assets during the second quarter of fiscal year

2006. The final adjustments, which did not have a material impact on our financial position, resulted in a reduction of $45,820 to the amount allocated to pad gas and an increase of an equal amount to acquired depreciable assets.

Fiscal year 2005 acquisitions

In November 2004, we acquired the Texas Chalk and Madison Systems from Devon Gas Services for $63,022 in cash which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $65,067 which included $63,022 of cash paid and liabilities assumed of $2,045. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets will be integrated into the Southeast Texas System and are expected to provide increased throughput capacity to our existing midstream assets. The acquisition was not material for pro forma disclosure purposes.

In January 2005, we acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. Under the terms of the transaction, the Partnership, through ETC OLP, our wholly-owned subsidiary, acquired all but a 2% limited partner interest in HPL. We financed this acquisition through a combination of cash on hand, borrowings under our credit facilities and a private placement with institutional investors of $350,000 of ETP Common Units. In addition, we acquired working inventory of natural gas stored in the Bammel storage facilities. The total purchase price of $1,350,212 (which included $1,039,521 of cash paid), net of cash acquired and liabilities assumed of $344,663, (including $800 in estimated acquisition costs), was allocated to the assets acquired and liabilities assumed. The HPL System consists of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4 Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables us to expand our current transportation systems into areas where we previously did not have a presence and, in combination with our current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in our transportation and storage operating segment.

Prior to June 29, 2005, ETC OLP owned a 50% interest in Vantex Gas Pipeline Company, LLC and a 50.5% interest in Vantex Energy Services, Ltd. On June 29, 2005, ETC OLP purchased the remaining interest in both Vantex Gas Pipeline, LLC and Vantex Energy Services, Ltd. for approximately $3,839 of cash paid, net of cash acquired. The Vantex Gas system is located in East Texas and consists of approximately 250 miles of pipeline. Vantex Energy Services provides energy related marketing services to small and medium sized producers and end users on the Vantex Gas Pipeline system. The acquisition was not material for pro forma disclosure purposes.

During the year ended August 31, 2005, HOLP acquired substantially all of the assets of ten propane businesses. The aggregate purchase price for these acquisitions totaled $30,772 which included $25,462 of cash paid, net of cash acquired, 120,550 ETP Common Units on a post-split basis issued valued at $2,500 and liabilities assumed of $2,810. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for these acquisitions:


	Texas Chalk and Madison Systems November 2004			Initial HPL Acquisition January 2005			Vantex June 2005			HOLP Acquisitions (Aggregated)
Cash and equivalents	$	—		$	191		$	1,081		$	5
Accounts receivable		—			321,214			6,066			875
Inventory		—			132,095			—			584
Other current assets		—			8,672			1			215
Investments in unconsolidated affiliate		—			32,940			—			—
Price risk management assets		—			30,300			—			—
Property, plant, and equipment		65,067			823,360			4,479			18,592
Intangibles		—			1,440			—			5,971
Goodwill		—			—			—			4,535

Total assets acquired		65,067			1,350,212			11,627			30,777

Accounts payable		(525	)		(253,784	)		(5,404	)		(233	)
Accrued expenses		(1,520	)		(18,344	)		(91	)		(181	)
Other current liabilities		—			(11,829	)		(132	)		(227	)
Other liabilities		—			(15,277	)		—			—
Price risk management liabilities		—			(30,300	)		—			—
Long-term debt		—			—			—			(2,169	)
Minority interest		—			(15,129	)		—			—

Total liabilities assumed		(2,045	)		(344,663	)		(5,627	)		(2,810	)

Net assets acquired	$	63,022		$	1,005,549		$	6,000		$	27,967

We recorded the following intangible assets in conjunction with these acquisitions:


Customer lists (3-15 years)	$	3,456
Non-compete agreements (5 to 10 years)		1,326

Total amortized intangible assets		4,782

Trademarks and trade names		2,629
Goodwill		4,535

Total intangible assets and goodwill acquired	$	11,946

Goodwill was warranted because these acquisitions enhance our current operations and certain acquisitions are expected to reduce costs through synergies with existing operations. We assigned all of the goodwill acquired to the retail propane segment of HOLP. We expect the entire $4,535 of goodwill acquired to be tax deductible.

The purchase prices were allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition.

During the third quarter of fiscal year 2005, we completed a verification of the working gas inventory contained in the storage facilities we acquired in two acquisitions during fiscal year 2004 and adjusted the preliminary allocations of the purchase prices to reflect the verified amounts.

During fiscal year 2006, we adjusted the preliminary allocations for the HPL acquisition (1) to reflect the working capital settlement with AEP occurring in the first quarter of fiscal year 2006 and (2) to reflect the final purchase price allocation as discussed above.

Fiscal year 2004 acquisitions

On June 2, 2004, ETC OLP acquired the transportation assets of TXU Fuel Company (formerly the TUFCO System now referred to as the ET Fuel System) for $498,571 in cash. The assets include approximately 2,000 miles of intrastate pipeline and related storage facilities located in Texas, with a total system capacity of 1.3 billion cubic feet or natural gas per day. The purchase price was funded with borrowings under ETC OLP’s amended debt agreement. These assets allow ETC OLP to provide multiple services to producers in four major producing areas of Texas, as well as providing access to major natural gas markets. In addition, these assets are expected to provide us significant growth opportunities going forward. The acquisition was accounted for using the purchase method under SFAS 141. The purchase price was initially allocated based on the estimated fair values of the individual assets acquired and the liabilities assumed at the date of the acquisition. The final allocation of the purchase price was completed in the third quarter of fiscal year 2005 upon the completion of an independent appraisal.

During the period from January 20, 2004 to August 31, 2004, HOLP acquired substantially all of the assets of three propane companies. The aggregate purchase price for these acquisitions totaled $16,967, which included liabilities assumed of $268. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. These acquisitions were financed primarily with the HOLP Senior Revolving Acquisition Facility and were accounted for by the purchase method under SFAS 141.

The assets acquired and purchase price allocation of acquisitions during the year ended August 31, 2004 are as follows:


	ET Fuel System June 2, 2004			HOLP Acquisitions (Aggregated) January 20, 2004 to August 31, 2004
Accounts receivable	$	—		$	1,612
Inventory		—			335
Other current assets		57			—
Property, plant and equipment		499,789			8,024
Intangibles		—			1,560
Goodwill		10,327			5,437

Total assets acquired		510,173			16,968

Accrued expenses		(758	)		(52	)
Other current liabilities		—			(1	)
Deposits from vendor		(750	)		—
Exchanges payable		(10,094	)		—
Long-term debt		—			(215	)

Total liabilities assumed		(11,602	)		(268	)

Net assets acquired	$	498,571		$	16,700

The results of operations for these acquisitions are included in our consolidated statement of operations from the date of the respective acquisition.

Pro Forma Results of Operations (Unaudited)

The following unaudited pro forma consolidated results of operations for the year ended August 31, 2006 are presented as if the Titan acquisition had been made on September 1, 2005. The pro forma consolidated results of operations for the year ended August 31, 2005 are presented as if the Titan and HPL acquisitions had been made on September 1, 2004. The pro-forma consolidated results of operations for the year ended August 31, 2004, are presented as if the HPL acquisition, the ET Fuel System acquisition and the Energy Transfer Transactions had been made on September 1, 2003. The pro forma effects of the Titan acquisition have not been included in the pro forma consolidated results of operations for the year ended August 31, 2004. The pro forma consolidated net income and earnings per unit include the income from discontinued operations as presented on the consolidated statements of operations for the years ended August 31, 2005 and 2004.


	Year Ended August 31, 2006		Year Ended August 31, 2005		Year Ended August 31, 2004
Revenues	$	8,194,053	$	8,210,903	$	6,316,534
Net income	$	113,657	$	263,134	$	81,708
Limited Partners’ interest in net income	$	113,011	$	260,969	$	81,050
Basic earnings per Limited Partner Unit	$	0.85	$	2.33	$	0.90
Diluted earnings per Limited Partner Unit	$	0.84	$	1.96	$	0.72

Included in the pro forma results of operations for our fiscal year ended August 31, 2005 is approximately $107.4 million of Titan income related to the cancellation of debt through Titan’s bankruptcy process, net of $7.6 million of Titan reorganization expenses and $3.3 million of Titan fresh start expenses. This income is net of the impact of minority interest and is not excluded from our pro forma income for the year ended August 31, 2005 as it does not result directly from the Titan acquisition. However, this income is non-recurring in nature and we do not expect to realize similar income in the future.

The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma consolidated results of operations do not include the purchase of the remaining 50% of Vantex Gas Pipeline Company, LLC and the 50.5% interest in Vantex Energy Services, Ltd. on June 29, 2005 as the impact is not material. In addition, the acquisition of the remaining 2% interest of HPL and the eight propane businesses that were acquired during the year ended August 31, 2006 and the propane acquisitions and Texas Chalk and Madison Systems acquisitions that were completed during the years ended August 31, 2005 and 2004, are not included in the pro forma consolidated results of operations above as the impact of such acquisitions is not material. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

Dispositions

On April 14, 2005, we sold our Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for $191,606 in cash and recorded a gain on the sale during the fiscal year 2005 of $44,013, net of income taxes of $1,829 and minority interest. The Elk City System was included in our midstream segment. The sale of the Elk City System has been accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-lived Assets. These results are presented as net amounts in the consolidated statements of operations for the year with prior periods restated to conform to the current presentation. Selected operating results for these discontinued operations are presented in the following table:


	Year Ended August 31, 2005			Year Ended August 31, 2004
Revenues	$	105,542		$	135,297
Cost and expenses		(100,044	)		(129,134	)
Minority interest in income from discontinued operations		(3,217	)		(2,705	)

Income from discontinued operations	$	2,281		$	3,458

3.	SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Revenue Recognition

Revenues for sales of natural gas, natural gas liquids (“NGLs”) including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor, transportation, treating, compression, and gas processing, is recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Tank rent is recognized ratably over the period it is earned.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which 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 process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. In many cases, 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.

We conduct our 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. We also 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 that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

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 statement of operations. As a result of our trading activities, discussed in Note 10, and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to the risk management committee which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy.

Our transportation and storage results are determined primarily by the amount of capacity our 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 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. Our transportation and storage segment also generates its revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities, primarily on the ET Fuel system, and to a lesser extent, at HPL.

Our transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System. Generally, HPL purchases its natural gas from the market, including purchases from the midstream segment’s producer services, and from producers at the wellhead. To the extent the natural gas is obtained from producers, it is purchased at a discount to a specified price and is typically resold to customers at a price based on a published index.

We engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir on its HPL System. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. Since the acquisition of HPL, we have continually managed our positions to enhance the future profitability of our storage position. We expect margins from the HPL System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage segments are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended August 31, 2006 represent the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, deferred taxes, and general business and medical self-insurance reserves. Actual results could differ from those estimates.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, such balances may be in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limit.

The net change in cash due to changes in operating assets and liabilities (net of acquisitions) is comprised as follows:


	Year Ended August 31,
	2006			2005			2004
Accounts receivable	$	189,719		$	(242,885	)	$	(101,974	)
Accounts receivable from related companies		1,828			(2,260	)		(35	)
Inventories		(83,448	)		(105,441	)		35,457
Deposits paid to vendors		(22,772	)		(62,011	)		16,030
Exchanges receivable		12,402			(18,412	)		(7,479	)
Prepaid expenses and other		(27,128	)		(5,123	)		2,532
Intangibles and other assets		(949	)		(415	)		(1,360	)
Other long-term assets		(1,738	)		(1,834	)		—
Accounts payable		(295,173	)		282,316			58,278
Accounts payable to related companies		(135	)		(1,083	)		685
Customer advances and deposits		(41,179	)		112,429			14,410
Exchanges payable		(9,050	)		9,320			1,436
Accrued and other current liabilities		72,585			9,639			(4,801	)
Other long-term liabilities		(13,179	)		(2,839	)		688
Income taxes payable		(2,063	)		(189	)		(315	)
Price risk management liabilities, net		119,900			(128,363	)		(3,163	)

Net change in operating assets and liabilities, net of effect of acquisitions	$	(100,380	)	$	(157,151	)	$	10,389

Noncash financing and supplemental cash flow information is as follows:


	Year Ended August 31,
	2006		2005		2004
NONCASH FINANCING ACTIVITIES:
Notes payable incurred on noncompete agreements	$	4,234	$	2,168	$	215

Issuance of subsidiary Common Units in connection with certain acquisitions	$	4,000	$	2,500	$	734

Distribution of ETP Common Units to redeem limited partner interests	$	—	$	19,287	$	—

Assets and subsidiary interests contributed by partners	$	—	$	55,884	$	1,743

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of $12,605, $191 and $926 capitalized for August 31, 2006, 2005 and 2004, respectively	$	159,541	$	90,885	$	37,971

Cash paid during the period for income taxes	$	38,138	$	7,538	$	7,227

100

Marketable Securities

Marketable securities we own are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at fair value.

Accounts Receivable

Our midstream and transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master set off agreement). Management reviews midstream and transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debt in our accounts receivable of the midstream and transportation and storage segments was not significant at the end of the 2006 and 2005 fiscal years; therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was $975, $0 and $123 in bad debt expense recorded during the years ended August 31, 2006, 2005 and 2004, respectively, in the midstream and transportation and storage segments.

We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.

HOLP and Titan grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane and Titan’s retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane segments are recorded as amounts are billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers and any specific disputes.

Accounts receivable consisted of the following:


	August 31, 2006			August 31, 2005
Accounts receivable - midstream and transportation and storage	$	570,569		$	782,090
Accounts receivable - propane		108,976			69,014
Less – allowance for doubtful accounts		(4,000	)		(4,076	)

Total, net	$	675,545		$	847,028

The activity in the allowance for doubtful accounts for the retail and wholesale propane segments consisted of the following:


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
Balance, beginning of the period	$	4,076		$	1,667		$	—
Provision for loss on accounts receivable		1,723			5,523			1,667
Accounts receivable written off, net of recoveries		(1,799	)		(3,114	)		—

Balance, end of period	$	4,000		$	4,076		$	1,667

The HOLP accounts receivable as of January 20, 2004 were established at estimated fair value in connection with the Energy Transfer Transactions. The Titan accounts receivable as of June 1, 2006 were established at estimated fair value in connection with the Titan acquisition.

101

Inventories

Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are valued at the lower of cost or market utilizing the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:


	August 31, 2006		August 31, 2005
Natural gas, propane and other NGLs	$	371,430	$	277,209
Appliances, parts and fittings and other		15,710		14,236

Total inventories	$	387,140	$	291,445

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. Management believes market value approximates cost.

Property, Plant and Equipment

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

We review long-lived assets for impairment at least annually and whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. No impairment of long-lived assets was required during the periods presented.

Components and useful lives of property, plant and equipment were as follows (excluding assets held for sale):


	August 31, 2006			August 31, 2005
Land and improvements	$	63,383		$	39,715
Buildings and improvements (10 to 30 years)		70,976			51,065
Pipelines and equipment (10 to 65 years)		2,212,805			2,030,221
Natural gas storage (40 years)		91,177			40,817
Bulk storage, equipment and facilities (3 to 30 years)		108,834			58,825
Tanks and other equipment (5 to 30 years)		472,944			346,924
Vehicles (5 to 10 years)		120,710			81,998
Right of way (20 to 65 years)		112,185			98,218
Furniture and fixtures (3 to 10 years)		16,283			11,995
Linepack		24,821			25,100
Pad Gas		57,327			102,557
Other (5 to 10 years)		27,395			17,893

		3,378,840			2,905,328
Less – Accumulated depreciation		(274,809	)		(157,256	)

		3,104,031			2,748,072
Plus – Construction work-in-process		644,583			139,678

Property, plant and equipment, net	$	3,748,614		$	2,887,750

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Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate of our revolving credit facility. A total of $12,605, $191 and $926 of interest was capitalized for pipeline construction projects for the years ended August 31, 2006, 2005 and 2004, respectively.

Depreciation expense for the years ended August 31, 2006, 2005 and 2004 was $119,369, $96,636 and $50,097, respectively.

Asset Retirement Obligation

We account for our asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, (“SFAS 143”). SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, an entity would recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

We have completed the assessment of SFAS 143, and have determined that we are obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2006 or August 31, 2005 because the settlement dates were indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.

We adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”) on August 31, 2006. FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement of the obligation are uncertain. These conditional obligations were not previously addressed by SFAS 143. FIN 47 requires us to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 did not have a material impact on our consolidated results of operations, cash flows or financial position.

Goodwill

Goodwill is associated with acquisitions made for our midstream, transportation and storage, and retail propane segments. Of the $633,998 balance in goodwill, $303,870 is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). Based on the annual impairment tests performed in the fourth fiscal quarter, there was no impairment as of August 31, 2006, 2005 or 2004. The changes in the carrying amount of goodwill for the years ended August 31, 2006 and 2005 were as follows:

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	Midstream		Transportation and Storage		Retail Propane			Other		Total
Balance as of August 31, 2004	$	13,409	$	—	$	300,311		$	29,556	$	343,276
Fair value adjustment for final purchase allocation related to the Energy Transfer Transactions		—		—		(4,842	)		—		(4,842	)
Goodwill acquired during the year		—		10,327		4,814			33		15,174

Balance as of August 31, 2005		13,409		10,327		300,283			29,589		353,608
Goodwill acquired during the year		—		—		280,390			—		280,390

Balance as of August 31, 2006	$	13,409	$	10,327	$	580,673		$	29,589	$	633,998

Goodwill acquired during the year includes, as applicable, final purchase price adjustments for prior year acquisitions. The final assessment of asset values related to the Titan acquisition is expected to be completed in the first or second quarter of fiscal year 2007 upon the completion of the final independent appraisal. There is no guarantee that the preliminary allocation will not change.

The final assessment of asset values related to the Energy Transfer Transactions and the ET Fuel acquisition was completed during the first and third quarters of fiscal year 2005, respectively. The determination of the final fair values resulted in adjustments to the allocations made in 2004 and consisted of changes from the initially determined values as follows:


	ET Fuel Acquisition			Energy Transfer Transactions
Increase (decrease) in goodwill	$	10,327		$	(4,842	)
Increase in intangibles	$	—		$	10,034
Increase in accrued expenses	$	(233	)	$	—
Increase in exchanges payable	$	(10,094	)	$	—
Decrease in property and equipment	$	—		$	(5,192	)

Investment in Affiliates

We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influences over, but do not control, the investee’s operating and financial policies.

Prior to June 29, 2005, ETC OLP owned a 50% interest in Vantex Gas Pipeline Company, LLC and a 50.5% interest in Vantex Energy Services, Ltd. These investments were accounted for under the equity method of accounting. On June 29, 2005 we bought the remaining 50% interest in Vantex Gas Pipeline and the remaining 49.5% interest of Vantex Energy Services, Ltd. The results of operations of the 100% owned entities are recognized on a consolidated basis from the date of acquisition. The Vantex system is located in East Texas and is composed of approximately 250 miles of pipeline. Vantex Energy Services provides energy related marketing services to small and medium sized producers and end users on the Vantex Gas Pipeline system.

We also own a 49% interest in Ranger Pipeline, L.P. (“Ranger”), which owns a 50% interest in Mountain Creek Joint Venture (“Mountain Creek”). Mountain Creek is located in North Texas and is composed of approximately 15 miles of pipeline. Mountain Creek supplies gas to an electric generation plant and earns the majority of its yearly income between the months of June and October. We account for our investment in Ranger using the equity method of accounting.

As a result of the HPL acquisition (see Note 2), we acquired a 50% ownership interest in Mid-Texas Pipeline Company (“Mid-Texas”) which owns approximately 139 miles of transportation pipeline that connects various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. We do not exercise management control over Mid-Texas, and, therefore, the investment is accounted for using the equity method of accounting.

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On July 18, 2005, we entered into a propane joint venture agreement. We contributed cash of $2,304 and a note payable of $2,000 for our 50% interest in this joint venture. This investment is accounted for using the equity method of accounting.

We entered into a joint venture to own a 50% interest in NSL Energy Marketing (“NSL”), a limited partnership, in June 2006. The joint venture was formed to market the capacity of the recently completed north side loop pipeline in north Texas. We account for our investment in NSL using the equity method of accounting.

Intangibles and Other Assets

Intangibles and other assets are stated at cost net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other assets were as follows:


	August 31, 2006					August 31, 2005
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortized intangible assets -
Noncompete agreements (5 to 15 years)	$	31,593	$	(13,012	)	$	29,278	$	(8,051	)
Customer lists (3 to 15 years)		87,480		(11,640	)		50,148		(6,612	)
Financing costs (3 to 15 years)		23,751		(4,721	)		23,469		(1,344	)
Consulting agreements (2 to 7 years)		132		(122	)		132		(75	)
Other (10 years)		2,677		(422	)		477		(191	)

Total		145,633		(29,917	)		103,504		(16,273	)
Unamortized intangible assets -
Trademarks		64,842		—			29,447		—
Other assets		5,177		—			1,413		—

Total intangibles and other assets	$	215,652	$	(29,917	)		134,364	$	(16,273	)

Aggregate amortization expense of intangible assets was $10,267, $9,443 and $6,145 for the years ended August 31, 2006, 2005 and 2004, respectively. The estimated aggregate amortization expense for the next five fiscal years is $12,476 for 2007; $11,400 for 2008; $10,373 for 2009; $8,385 for 2010, and $7,649 for 2011.

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable in accordance with Statement of Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually at August 31, or more frequently if circumstances dictate, in accordance with SFAS 144. No impairment of intangible assets was required for the years ended of August 31, 2006, 2005 or 2004.

Customer Advances and Deposits

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month and from our propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Advances and deposits received from customers were $108,836 and $138,442 as of August 31, 2006 and 2005, respectively.

Fair Value of Financial Instruments

The carrying amounts of accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2006 was $3,206,469 and $3,246,253 respectively. At August 31, 2005 the aggregate fair value and carrying amount of long-term debt was $2,322,806 and $2,315,341, respectively.

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Shipping and Handling Costs

In accordance with EITF No. 00-10, Accounting for Shipping and Handling Fees and Costs, we have classified $108,409, $89,030 and $35,895 from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue for the years ended August 31, 2006, 2005 and 2004, respectively. Shipping and handling costs related to fuel sold are included in cost of sales. The remaining costs of approximately $69,647, $50,137 and $19,834 included in operating expenses reflect the cost of fuel consumed for compression and treating for the years ended August 31, 2006, 2005 and 2004, respectively. We do not separately charge propane shipping and handling costs to customers.

Costs and Expenses

Costs of products sold include actual cost of fuel sold adjusted for the effects of our hedging and other commodity derivative activities, storage fees and inbound freight on propane, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs related to propane, purchasing costs, and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

Issuances of Subsidiary Units

The Partnership accounts for the difference between the carrying amount of the Partnership’s investment in ETP and the underlying book value arising from issuances of units by ETP as capital transactions rather than selecting the income recognition method as permitted by SEC Staff Accounting Bulletin (“SAB”) No. 51 (see Note 7). If ETP issues units at a price less than the Partnership’s carrying value per unit, the Partnership assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the Partnership’s consolidated statement of operations. The Partnership did not recognize any impairment related to the issuance of ETP units during the fiscal years ended August 31, 2006, 2005 or 2004.

Contributions to Subsidiary

As discussed in Note 1, the Partnership directly and indirectly owns all of the equity interests in ETP GP, the General Partner of ETP. ETP GP is required to make contributions to ETP each time ETP issues Common Units in order to maintain its 2% general partner ownership in ETP. These contributions are generally netted from the funds the Partnership receives from distributions for ETP. ETP GP was required to contribute $2,784 and $10,418 for the years ended August 31, 2006 and 2005.

Income Taxes

ETE is a limited partnership. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under the Partnership Agreement.

We are generally 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 periods ended August 31, 2006, 2005 and 2004, our non-qualifying income did not, or was not expected to, exceed the statutory limit.

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Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

Accounting for Derivative Instruments and Hedging Activities

We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. We apply Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended to account for our derivative financial instruments. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. For further discussion and detail of our derivative instruments and/or hedging activities see Note 10 – “Price Risk Management Assets and Liabilities”.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flow from operating activities, in the same category as the cash flows from the items being hedged.

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 and NGLs. We enter into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date. We had net deposits with derivative counterparties of $87,806 and $65,034 as of August 31, 2006 and 2005, respectively, reflected as deposits paid to vendors on our consolidated balance sheets.

Allocation of Income (Loss)

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 7).

Recently Issued Accounting Standards

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process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We are currently evaluating the statement and have not yet determined the impact of such on our financial statements.

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

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

4.	NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s unit-based compensation plans had been issued during the respective periods. Such units have been determined based on the treasury stock method. The basic and diluted average limited partner units outstanding for the years ended August 31, 2005 and 2004 have been restated to reflect the 54.41% unit conversion factor to an

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equivalent number of Common Units effected in February 2006 as a result of ETE’s IPO (see Note 7). A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:


	Year Ended August 31,
	2006			2005			2004
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	106,531		$	145,539		$	445,779

Weighted average limited partner units		133,820,176			111,939,537			97,474,988

Limited Partners’ income per unit from continuing operations	$	0.80		$	0.89		$	4.54
Limited Partners’ income per unit from discontinued operations		—			0.41			0.04

Basic net income per limited partner unit:	$	0.80		$	1.30		$	4.58

Diluted Net Income per Limited Partner Unit
Limited Partners’ interest in net income	$	106,531		$	145,539		$	445,779
Dilutive effect of subsidiary Unit grants		(343	)		(188	)		(27	)

Diluted net income available to limited partners	$	106,188		$	145,351		$	445,752

Weighted average limited partner units		133,820,176			111,939,537			97,474,988
Dilutive effect of Incentive Units		—			20,855,935			34,448,263

Weighted average limited partner units, assuming dilutive effect of Employee Incentive Units		133,820,176			132,795,472			131,923,251

Limited Partners’ income per unit from continuing operations	$	0.79		$	0.75		$	3.35
Limited Partners’ income per unit from discontinued operations		—			0.34			0.03

Diluted net income per limited partner unit	$	0.79		$	1.09		$	3.38

5.	MINORITY INTERESTS:

The following table summarizes the changes in minority interest liability:


	Year Ended August 31,
	2006			2005
Balance, beginning of the year	$	1,212,135		$	803,220
Minority interest in net income of subsidiaries		303,752			162,242
Distributions and other		(193,002	)		(116,953	)
Compensation under subsidiary employee unit awards		7,038			1,607
Gain on sale of subsidiary Common Units, as discussed above		—			(59,557	)
Contribution of Units from FHM (see Note 7)		—			(55,884	)
Sale of investment in ETP GP to FHM (see Note 7)		—			2,631
Premium on ETE’s purchase of ETP units		54,001			—
Change in other comprehensive income allocable to minority interests		63,415			(58,645	)
Acquisition of equity investee by subsidiary		—			15,129
Acquisition of the remaining 2% of HPL		(16,667	)		—
Subsidiary equity offering		—			507,724
Subsidiary units issued in connection with certain acquisitions		4,000			2,500
Retirement of employee incentive units (see Note 7 )		—			8,121
Distribution of interest in consolidated subsidiary (see Note 1)		4,455			—

Balance, end of the year	$	1,439,127		$	1,212,135

6.	DEBT OBLIGATIONS:

Our debt obligations consist of the following:


	August 31, 2006		August 31, 2005		Maturities
ETP Senior Notes:
2005 5.95% Senior Notes, net of discount of $1,985 and $2,160, respectively.	$	748,015	$	747,840	One payment of $750,000 due February 1, 2015. Interest is paid semi-annually.

2005 5.65% Senior Notes, net of discount of $358 and $408, respectively.		399,642		399,592	One payment of $400,000 due August 1, 2012. Interest is paid semi-annually.

HOLP Senior Secured Notes:
1996 8.55% Senior Secured Notes		60,000		72,000	Annual payments of $12,000 due each June 30^th through 2011. Interest is paid semi-annually.

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1997 Medium Term Note Program:
7.17% Series A Senior Secured Notes	9,600	12,000	Annual payments of $2,400 due each November 19^th through 2009. Interest is paid semi-annually.
7.26% Series B Senior Secured Notes	14,000	16,000	Annual payments of $2,000 due each November 19^th through 2012. Interest is paid semi-annually.
6.50% Series C Senior Secured Notes	357	714	Annual payments of $357 due March 13, 2007. Interest is paid semi-annually.
2000 and 2001 Senior Secured Promissory Notes:
8.47% Series A Senior Secured Notes	3,200	6,400	Annual payments of $3,200 due each August 15^th through 2007. Interest is paid quarterly.
8.55% Series B Senior Secured Notes	18,286	22,857	Annual payments of $4,571 due each August 15^th through 2010. Interest is paid quarterly.
8.59% Series C Senior Secured Notes	21,250	27,000	Annual payments of $5,750 due August 15, 2007, $4,000 due August 15, 2008, and $5,750 due each August 15, 2009 and 2010. Interest is paid quarterly.
8.67% Series D Senior Secured Notes	58,000	58,000	Annual payments of $12,450 due August 15, 2008 and 2009, $7,700 due August 15, 2010, $12,450 due August 15, 2011, and $12,950 due August 15, 2012. Interest is paid quarterly.
8.75% Series E Senior Secured Notes	7,000	7,000	Annual payments of $1,000 due each August 15, 2009 through 2015. Interest is paid quarterly.
8.87% Series F Senior Secured Notes	40,000	40,000	Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly.
7.21% Series G Senior Secured Notes	7,600	11,400	Annual payments of $3,800 due each May 15^th through 2008. Interest is paid quarterly.
7.89% Series H Senior Secured Notes	7,273	8,000	Annual payments of $727 due each May 15^th through 2016. Interest is paid quarterly.
7.99% Series I Senior Secured Notes	16,000	16,000	One payment of $16,000 due May 15, 2013. Interest is paid quarterly.
Revolving Credit Facilities and Term Loans:
ETE Senior Secured Revolving Credit Facility (including Swingline loan option)	466,291	—	Available through February 8, 2011. See terms below under “Revolving Credit Facilities and Term Loans.
ETE Senior Secured Term Loan	150,000	—	Due February 8, 2012. See terms below under “Revolving Credit Facilities and Term Loans.
ETE 2005 Senior Secured Term Loan	—	600,000	Paid and retired in February 2006.
ETP Revolving Credit Facility (including Swingline loan option)	1,162,624	201,000	Available through June 2011 – see terms below under “Revolving Credit Facilities and Term Loans”.
ETP $250,000 Revolving Credit Facility	20,000	—	Paid and retired in October 2006.

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HOLP Fourth Amended and Restated Senior Revolving Credit Facility		20,000			51,642		Available through June 30, 2011 – see terms below under “Revolving Credit Facilities and Term Loans”.

Other Long-Term Debt:
Notes Payable on noncompete agreements with interest imputed at rates averaging 7.56 % and 7.48% for the years ended August 31, 2006 and 2005, respectively		14,204			15,284		Due in installments through 2014.

Other		2,911			2,612		Due in installments through 2024.

		3,246,253			2,315,341
Current maturities of long-term debt		(40,607	)		(39,376	)

	$	3,205,646		$	2,275,965

Registration Statement

On August 9, 2006, ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register up to $1,500,000 aggregate offering price of a combination of ETP’s limited partner interests and debt securities. On October 23, 2006, ETP closed the issuance, under ETP’s $1,500,000 S-3 Registration Statement, of $400,000 of 6.125% Senior Notes due 2017 and $400,000 of 6.625% Senior Notes due 2036, and received net proceeds of approximately $791,000. ETP used the proceeds to pay borrowings and accrued interest under its Revolving Credit Facility. Interest on the 2017 Senior Notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 Senior Notes is payable semiannually on April 15 and October 15 of each year, beginning April 15, 2007. The notes are unsecured senior obligations and will be fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries.

Registered Exchange Offer

On November 23, 2005, ETP filed a registered exchange offer to exchange newly issued 5.65% Senior Notes due 2012 (the “2012 Notes”) that were registered under the Securities Act of 1933 (the “New Notes”), for a like amount of outstanding 5.65% Senior Notes due 2012, which had not been registered under the Securities Act (the “Old Notes”). On February 23, 2006, ETP commenced the exchange offer which closed on March 31, 2006. All $400,000 of the Old Notes were tendered pursuant to the exchange offer and were replaced with a like amount of New Notes. The sole purpose of the exchange offer was to fulfill ETP’s obligations under the registration rights agreement entered into in connection with our sale of the Old Notes on July 29, 2005. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes.

2005 Senior Notes

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

HOLP Senior Secured Notes

Revolving Credit Facilities and Term Loans

Simultaneous with the IPO the Parent Company entered into a Senior Secured Credit Agreement (the “Parent Company Senior Secured Credit Agreement”) with Wachovia Bank, National Association as Administrative

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Agent for a group of banks. The Parent Company Senior Secured Credit Agreement includes a $500.0 million Senior Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility replaced the 2005 Senior Secured Term Loan Agreement described below. The Parent Company Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $10.0 million and a daily rate based on LIBOR. On July 3, 2006, the Parent Company amended its Senior Secured Credit Agreement to provide for a $150.0 million Senior Secured Term Loan Facility due February 8, 2012.

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

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility and the Senior Secured Term Loan Facility bear interest at the Parent Company’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio. The weighted average interest rate was 6.76% for the amount outstanding on the Parent Company Senior Secured Revolving Credit Facility and 7.5% on the Senior Secured Term Loan Facility as of August 31, 2006.

The Senior Secured Credit Agreement is secured by a lien on the Parent Company’s assets, including the capital stock and assets of ETP LLC and ETP GP and its ownership of 36.4 million ETP Common Units.

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

On December 13, 2005 we entered into the $900,000 ETP Revolving Credit Facility which replaced the existing Revolving Credit Facility. The ETP Revolving Credit Facility was amended on June 29, 2006 (the Amended and Restated Credit Agreement) allowing for borrowings up to $1,300,000, expandable to $1,500,000. The Amended and Restated Credit Agreement is available through June 29, 2011 unless we elect (and the banks agree) the two successive options to extend the maturity date for a period of 364 days each. Amounts borrowed under the Amended and Restated Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Amended and Restated Credit Agreement has a Swingline loan option with a maximum borrowing of $75,000 at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating and the maximum fee is 0.175%. As of August 31, 2006 there was a balance of $1,145,000 in revolving credit loans, $17,624 in Swingline loans and $14,368 in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2006, was 6.04%. The total amount available under the Amended and Restated Revolving Credit Agreement as of August 31, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $123,008. The Amended and Restated Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP and Titan and its wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On September 25, 2006 we exercised the accordion feature and expanded the total amount of the facility to $1,500,000.

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Prior to December 13, 2005, we had available a $800,000 Revolving Credit Facility which bore interest at a rate based on either a Eurodollar rate, or a prime rate. The Revolving Credit Facility offered a Swingline loan option with the maximum borrowing of $30,000 at a daily rate based on the London market. The weighted average interest rate was 4.827% at August 31, 2005. We borrowed $475,000 under the Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of August 31, 2005, $201,000 was outstanding under the Revolving Credit Facility which included $15,000 under the Swingline option and also had outstanding Letters of Credit of $11,300. Total amount available under the Credit Agreement at August 31, 2005 was $587,700.

On May 31, 2006, we entered into a $250,000 Revolving Credit Facility, which matures under its terms on December 1, 2006. Amounts borrowed under this facility will bear interest at a rate based on either a Eurodollar rate or a base rate. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The $250,000 Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP, Titan and all of their direct and indirect wholly-owned subsidiaries. The $250,000 Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On July 3, 2006, we reduced our borrowing capacity on the Revolving Credit Facility to $200,000. All terms, and maturity date, as mentioned above remain unchanged. There was $20,000 outstanding on this facility as of August 31, 2006. The weighted average interest rate on the total amount outstanding at August 31, 2006 was 5.988%. This facility was paid and retired on October 18, 2006.

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

A $75,000 Senior Revolving Facility is available through June 30, 2011. The revolving facility is expandable to $150,000. The Facility has a swingline loan option with a maximum borrowing of $10,000 at a prime rate. Amounts borrowed under this Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.955% for the amount outstanding at August 31, 2006. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The sum of the loans, swingline loans and letters of credit may not exceed the maximum amount of revolving credit. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Facility. As of August 31, 2006, the Facility had a $20,000 balance outstanding. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Senior Revolving Facility. There were outstanding Letters of Credit of $1,002 at August 31, 2006. The sum of the loans made under the Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75,000 maximum amount of the Senior Revolving Facility.

Prior to August 31, 2006, HOLP also maintained a $75,000 Senior Revolving Acquisition Facility for acquisition of propane-related businesses. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. During the second quarter of fiscal year 2006, HOLP paid in full the outstanding indebtedness under this facility and cancelled the Senior Revolving Acquisition Facility.

Debt Covenants

The agreements for the Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility and ETP’s and the Operating Partnerships’ Senior Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to the Parent Company, 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.

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The Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility contain financial covenants as follows:

•

Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to Consolidated EBITDA of the Parent Company of not more than 4.50 to 1.00

•

Maximum Consolidated Leverage Ratio – Consolidated Funded Debt of the Parent Company and ETP to Consolidated EBITDA of ETP of not more than 5.50 to 1.00

•

Interest Coverage Ratio may not be less than 3.00 to 1.00

•

Value to Loan Ratio may not be less than 2.00 to 1.00

The most restrictive of the ETP and Operating Partnerships’ covenants require us to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

The Consolidated EBITDA used to determine these ratios is calculated in accordance with the debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months.

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. We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of August 31, 2006.

Future maturities of long-term debt for each of the next five fiscal years and thereafter are as follows:


2007	$	40,607
2008		46,954
2009		43,974
2010		41,470
2011		1,681,660
Thereafter		1,391,588

	$	3,246,253

7.	PARTNERS’ CAPITAL AND UNIT-BASED COMPENSATION PLANS:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common and Class B Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. The Partnership’s Common Units are registered under the Securities Act of 1934 and are listed for trading on the

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New York Stock Exchange. Each holder of a Common Unit and Class B 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 the Partnership’s 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 the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”

As of August 31, 2006, there were issued and outstanding 124,360,520 Common Units representing an aggregate 97.5% limited partner interest in the Partnership. There are also 2,521,570 Class B Units outstanding that are entitled to receive distributions in accordance with their terms.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

On February 8, 2006 we completed our IPO of 24,150,000 Common Units at a price of $21.00 per unit. In connection with this IPO, the Partnership’s limited partner units were converted to Common Units based on a conversion ratio of 54.41% (46.48% after the dilution effects of the IPO and issuance of Class B Units). As a result, the limited partner units of all prior periods have been restated to reflect the equivalent units on a post conversion basis. The conversion ratio was determined in deriving the Common Units outstanding held by the existing limited partners at the time of the IPO, based on an expected 3.33% yield on an estimated $96,100 of distributable cash flow expected by ETE. Proceeds, net of the underwriters’ discount and equity issue costs, were $474,741. We used a portion of the net proceeds of the IPO to redeem 6,650,000 Common Units from the then existing limited partners. We used the remaining net proceeds from the offering to repay $175,500 of the outstanding indebtedness plus accrued interest of the Partnership and to fund the purchase of 1,069,850 ETP Common Units and 2,570,150 ETP Class F Units for $132,387 ($36.37 per ETP Unit) and for general partnership purposes.

Upon the closing of the IPO, we also issued Class B Units to our management. Each Class B Unit represents a limited partner interest in the Partnership and will be convertible into a Common Unit on a one-for-one basis at the election of the holder at any time following the six month anniversary of their issuance.

Limited Partner Interests

The change in Limited Partner Interests during the three year period ended August 31, 2006 is a follows:


	Number of Units
	August 31, 2006		August 31, 2005		August 31, 2004
Balance, beginning of year	136,357,870		105,708,225		85,316,991
Vesting of incentive units	—		26,432,000		19,824,000
Units issued in exchange for property and subsidiary interests	—		—		567,234
Retirement of limited partner interest	—		(2,643,200	)	—
Issuance of additional limited partner interests	—		6,860,845		—
Limited Partner Units converted to Common Units at IPO	(136,357,870	)	—		—

Balance, end of year	—		136,357,870		105,708,225

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Prior to the Energy Transfer Transactions, ETE’s partnership agreement provided for 39,648,000 Incentive Units (the “ETE Incentive Units”), consisting of: 13,216,000 “Tier I Units;” 6,608,000 “Tier II Units;” 6,608,000 “Tier III Units;” and 13,216,000 “Tier IV Units;” to be granted to ETC Holdings, LP, one of ETE’s limited partners, if certain “Tier” payouts are achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 13,216,000 ETE Incentive Units vested and were converted to limited partner interests. In June 2005, the remaining “Tier” payout conditions as defined in the Partnership Agreement were achieved and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership. The fair value of the ETE Incentive Units was measured on the grant date in accordance with SFAS 123. Management determined the estimated fair value of the ETE Incentive Units on the grant date was insignificant due to ETE’s assets and operations at the time of inception did not appear to be sufficient to provide the payouts required with respect to each Tier. Accordingly, no expense was recorded in the Partnership’s 2005 or 2004 consolidated financial statements or at the time of conversion to limited partner interest in the Partnership for the vesting of the ETE Incentive Units.

On January 19, 2004, ETE issued 567,234 limited partner units valued at $1,743 to a group of limited partners in exchange for their contribution of various subsidiary partnership interests and an office building and related contents. These assets and subsidiary partnership interests were subsequently contributed to ETP in exchange for an increased limited partner interest in ETP.

In September 2004, ETE sold a 4.9995% limited partner interest in ETP GP and 5% of the member interest of ETP LLC to a group of executive managers of ETP pursuant to an agreement entered into concurrent with the Energy Transfer Transactions. On June 20, 2005, ETE exchanged with this group of executive managers a 5% limited partner interest, or 6,860,845 limited partner units, in ETE for 1,638,692 ETP Common Units and the 4.9995% limited partner interest in ETP GP and the 5% member interest in ETP LLC held by this group. In order to avoid potential ownership differences, 1,638,692 Common Units of ETP, which was equal to 5% of the number of Common Units of ETP to be held by ETE, were exchanged together with the 4.9995% limited partner interest in ETP GP and the 5% member interest of ETP LLC, which the units and GP interests together were deemed to be an equivalent value of the 5% limited partner interest in ETE, which was valued at $55,884. ETE recorded an additional investment in ETP at the fair value of the ETP Common Units received, and an additional investment in ETP GP and ETP LLC at the fair value of the interests in ETP GP and ETP LLC that were exchanged. The 6,860,845 limited partner interests were valued at $55,884. The transaction is recorded at fair value based on the guidance in paragraph 18 of APB 29, “Accounting for Nonmonetary Transactions”.

In May 2005, we exchanged 631,320 ETP Common Units we held and $1,046 in cash for the redemption of 2,643,200 limited partner interests in the Partnership, which were then retired. The fair value of the cash and ETP Common Units transferred in the redemption was determined to be no more than the fair value of the respective interests in the Partnership. A gain of $11,166 was recorded for the fair value of the ETP Common Units in excess of their related carrying value in connection with the redemption through interest and other income, net in our consolidated statement of operations.

Common Units

The change in Common Units during the year ended August 31, 2006 is as follows (no Common Units were outstanding prior to our IPO in February 2006):


	Number of Units August 31, 2006
Balance, beginning of year	—
Common Units issued to limited partner interests at IPO	116,503,277
Units issued in IPO	24,150,000
Redemptions, as discussed above	(6,650,000	)
Repurchase of Common Units	(9,642,757	)

Balance, end of year	124,360,520

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In July 2006, ETE agreed to repurchase 9,642,757 of its Common Units for $237,817 in an unsolicited offer from a former Unitholder. The Common Units were retired and canceled. The per unit price paid on the repurchase of units approximated the quoted market price at close, discounted at approximately 5%, on the date of purchase.

Class B Units

The change in Class B Units during the year ended August 31, 2006 is as follows (no Class B Units were outstanding prior to our IPO in February 2006):


		Number of Units August 31, 2006
Balance, beginning of year		—
Units issued to management, as discussed above		2,521,570

Balance, end of year		2,521,570

We recognized compensation expense of $52,953 for the grant date fair market value of the Class B Units issued.

Sale of Common Units by Subsidiary

On June 30, 2004, ETP completed the sale of 9,000,000 Common Units at a public offering price of $19.60 per unit. On July 2, 2004 ETP issued 1,350,000 Common Units to the Underwriters upon their exercise of their over-allotment option at the offering price of $19.60 per unit (unit and per unit prices have been adjusted to reflect ETP’s two-for-one split of its Common Units effected on January 27, 2005). Net proceeds from the Common Units offering and the exercise of the over-allotment option were $193,799 and were used to repay a portion of the outstanding indebtedness incurred to fund the ET Fuel System acquisition and for general partnership purposes. The Partnership recorded the difference between the carrying amount of the Partnership’s investment in ETP and the underlying book value as a capital transaction in the amount of $2,742 based on the Partnership’s ownership in ETP being diluted from 40.33% to 35.65% during the year ended August 31, 2004. The capital transaction is reflected in the Partnership’s balance sheet as an increase in limited partners’ capital in accordance with the guidance in SAB 51. No deferred taxes were recorded, and the transaction had no effect on the Partnership’s income.

On January 26, 2005, ETP sold $350,000 of Common Units in a private placement to institutional investors as part of the financing of the acquisition of HPL. In this private placement, ETP issued 6,296,294 unregistered Common Units for total consideration of $170,000, and ETP became obligated under a Units Purchase Agreement dated January 14, 2005 to issue an additional 6,666,666 Common Units for total consideration of $180,000. These Common Units were issued pursuant to an effective shelf registration statement on March 18, 2005. ETP used the proceeds from these private placements to finance a portion of the HPL acquisition. Concurrent with this sale of Common Units, the Partnership recorded the difference between the carrying amount of the Partnership’s investment in ETP and the underlying book value as a capital transaction in the amount of $36,648 based on the Partnership’s ownership in ETP being diluted from 35.58% to 31.07%. The capital transaction is reflected in the Partnership’s balance sheet as an increase in limited partners’ capital in accordance with the guidance in SAB 51. No deferred taxes were recorded, and the transaction had no effect on the Partnership’s income.

On February 8, 2006, ETE purchased 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in ETP. The price per unit paid for each of the Common Units and Class F Units was equal to $36.37 per unit, the New York Stock Exchange closing price of the ETP’s Common Units on February 8, 2006. The Partnership recorded the premium of $54,001 between the underlying book value before and after the purchase of the ETP Units as a reduction of ETE’s limited partners’ capital with an adjustment to the minority interest to account for the effect of the increase in ETE’s ownership percentage in ETP from 30.63% to 32.92%. We purchased the ETP Class F Units in a private placement. The terms of such Class F Units provided that they may be converted into Common Units upon an approval by a majority of the ETP Common Unitholders and that such units were entitled to distributions. The Class F Units were converted to ETP Common Units on August 16, 2006.

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Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. Our only cash-generating assets currently consist of limited and general partner interests, including incentive distribution rights, in ETP from which we receive quarterly distributions. We currently have no independent operations outside of our interests in ETP.

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


	2006			2005			2004
Limited Partners Interests	$	80,203		$	57,671		$	20,411
General Partner Interest		6,931			4,237			1,059
Incentive Distribution Rights		64,436			27,971			2,890
Less holdbacks (a)		(2,287	)		(8,182	)		—

Total distributions received from ETP	$	149,283		$	81,697		$	24,360

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

Our distributions declared since our IPO in February 2006 are summarized as follows:


Record Date	Payment Date	Amount per Unit
March 31, 2006	April 19, 2006	$	0.0578
June 30, 2006	July 19, 2006	$	0.2375

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

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


	2006		2005
Limited Partners -
Limited Partners (a)	$	34,010	$	666,751
Common Units		65,905		—
Class B Units		745		—
General Partners		599		4,861

Total distributions declared	$	101,259	$	671,612

(a)	Distributions to Limited Partners represent distributions to our Limited Partners prior to our IPO in February 2006.

All distributions were made from Available Cash from our operating surplus.

ETP’s Quarterly Distribution of Available Cash

The Partnership Agreement of ETP requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of

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ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.

Distributions by ETP from operating surplus for any quarter in an amount equal to 100% of Available Cash will generally be made as follows to its partners, subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of quarterly cash distributions are achieved ($0.275 per unit):

•

First, 98% to all Common, Class E and Class G Unitholders, in accordance with their percentage interests, and 2% to the General Partner, until each Common Unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”);

•

Second, 98% to all Common, Class E and Class G Unitholders, in accordance with their percentage interests, and 2% to the General Partner, until each Common Unit has received $0.275 per unit for such quarter (the “first target distribution”);

•

Third, 85% to all Common and Class E and Class G Unitholders, in accordance with their percentage interests, 13% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner, until each Common Unit has received at least $0.3175 per unit for such quarter (the “second target distribution”);

•

Fourth, 75% to all Common, Class E and Class G Unitholders, in accordance with their percentage interests, 23% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner, until each Common Unit has received at least $0.4125 per unit for such quarter; (the “third target distribution”); and

•

Fifth, thereafter, 50% to all Common, Class E and Class G Unitholders, in accordance with their percentage interests, 48% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner.

Notwithstanding the foregoing, any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E unit may not exceed $1.41 per year. See Note 17 for information related to our purchase of ETP’s Class G Units in November 2006.

ETP’s distributions declared during the years ended August 31, 2006, 2005 and 2004 are summarized as follows:


	Record Date	Payment Date	Amount per Unit
Fiscal Year 2006
	September 30, 2005	October 14, 2005	$	0.5000
	January 4, 2006	January 13, 2006	$	0.5500
	March 24, 2006	April 14, 2006	$	0.5875
	June 30, 2006	July 14, 2006	$	0.6375
	June 30, 2006 (1)	July 14, 2006	$	0.0325
Fiscal Year 2005
	October 7, 2004	October 15, 2004	$	0.4125
	January 5, 2005	January 14, 2005	$	0.4375
	March 16, 2005	April 14, 2005	$	0.4625
	July 8, 2005	July 14, 2005	$	0.4875
Fiscal Year 2004
	April 2, 2004	April 14, 2004	$	0.3500
	July 2, 2004	July 15, 2004	$	0.3750

(1)

Special SCANA distribution - On June 20, 2006, ETP announced that the Board of Directors of its General Partner declared a special distribution of $0.0325 per Limited Partner Unit related to the proceeds received by ETP in connection with the SCANA litigation settlement (see Note 10). 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.

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On May 1, 2006, ETP’s Partnership Agreement was amended to permit ETP’s General Partner, pursuant to its General Partner authority, to declare the next quarterly distribution prior to the close of such quarter.

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

The total amount of ETP distributions declared relating to the years ended August 31, 2006, 2005 and 2004 are as follows:


	2006		2005		2004
Limited Partners -
Common Units	$	248,237	$	173,802	$	52,963
Class D Units		—		—		5,405
Class C Units (1)		3,599		—		—
Class F Units		3,232		—		—

General Partners -
2% Ownership		6,981		4,390		1,392
Incentive distribution rights		81,722		28,847		3,623

Total distributions declared	$	343,771	$	207,039	$	63,383

(1)	Special SCANA distribution – see discussion above.

All distributions were made from Available Cash from ETP’s operating surplus.

On August 16, 2006, all the ETP Class F Units were converted to ETP Common Units and ceased to have the right to participate in ETP distributions of available cash from operating surplus as itemized above.

Unit Based Compensation Plans

On September 1, 2005, we adopted the modified prospective provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”). Adoption of SFAS 123R did not have a material effect on our income from continuing operations.

We recognized compensation expense of $59,991, $1,608 and $42 for the years ended August 31, 2006, 2005 and 2004, respectively, related to unit-based compensation plans of ETP and ETE.

ETE Incentive Units

ETE’s Partnership Agreement provided for 39,648,000 Incentive Units (the “ETE Incentive Units”), consisting of: 13,216,000 “Tier I Units;” 6,608,000 “Tier II Units;” 6,608,000 “Tier III Units;” and 13,216,00 “Tier IV Units” to be granted to ETC Holdings, LP (“ETC Holdings”), one of ETE’s limited partners if certain “Tier” payouts were achieved. As a result of the Energy Transfer Transactions in January 2004, a total of 13,216,000 ETE Incentive Units held by ETC Holdings vested and were converted to limited partner interests in the Partnership. In June 2005, the remaining “Tier” payout conditions as defined in the Partnership Agreement were achieved, and the “Tier II Units”, “Tier III Units” and the “Tier IV Units” also vested and were converted to limited partner interests in the Partnership. The fair value of the ETE Incentive Units was measured on the grant date in accordance with SFAS 123. Management determined that the estimated fair value of the ETE Incentive Units on the grant date was insignificant because ETE’s assets and operations at the time of inception did not appear to be sufficient to provide the payouts required with respect to each Tier. Accordingly, no expense was recorded in the Partnership’s consolidated financial statements as of August 31, 2005, or 2004 or at the time of conversion to limited partner interests in the Partnership for the vesting of the ETE Units.

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ETE Long-Term Incentive Plan

Upon completion of ETE’s IPO in February 2006, 2,521,570 Class B Units were issued to FEM Group, LP, a partnership owned by members of management. These Class B Units were not subject to vesting. Each Class B unit represents a limited partner interest in ETE, is convertible into a Common Unit and is otherwise comparable to a Common Unit. The number and value of Class B Units issued were based on an independent appraisal. Consequently, as this represents an employee stock grant, compensation expense of $52,953 was recorded as selling, general and administrative expense at the time of the issuance of the Class B Units, and is reflected in Partnership’s consolidated statement of operations for the year ended August 31, 2006.

In addition, the Compensation Committee of the Board of Directors of ETP’s General Partner may from time to time grant additional awards to employees, directors and consultants of ETE’s General Partner and its affiliates who perform services for ETE. The plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units, excluding the Class B Units discussed above. As of August 31, 2006, other than the Class B Units discussed above, no awards were outstanding under the ETE Long-Term Incentive plan.

ETP Unit-Based Compensation Plans

2004 Unit Plan

On June 23, 2004 at a special meeting of ETP’s Common Unitholders, ETP’s Common Unitholders approved the terms of its 2004 Unit Plan (the “Plan”), which provides for awards of ETP Common Units and other rights to ETP’s employees, officers, and directors. The maximum number of ETP Common Units that may be granted under this Plan is 1,800,000 total units issued. Any awards that are forfeited or which expire for any reason or any units which are not used in the settlement of an award will be available for grant under the Plan. Units to be delivered upon the vesting of awards granted under the Plan may be (i) units acquired by ETP in the open market, (ii) units already owned by ETP or ETP’s General Partner, (iii) units acquired by ETP or its General Partner directly from ETP, or any other person, (iv) units that are registered under a registration statement for this Plan, (v) Restricted Units, or (vi) any combination of the foregoing.

The 2004 Plan is administered by the Compensation Committee of the ETP’s Board of Directors (“ETP’s Compensation Committee”) and may be amended from time to time by ETP’s Board; provided however, that no amendment will be made without the approval of a majority of ETP’s Unitholders (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the Plan; (iii) materially increase the cost of the Plan to ETP; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later than the 10^th anniversary of its original effective date (June 23, 2014).

Employee Grants.

ETP’s Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any Change in Control as defined by the Plan, or upon such terms as ETP’s Compensation Committee may require at the time the award is granted.

Employee grants awarded under the 2004 unit plan will vest over a three-year period based upon the achievement of certain performance criteria. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. Vesting occurs based upon the total return to ETP’s Unitholders as compared to a group of Master Limited Partnership peer companies. One third of the awards will vest and convert to ETP Common Units annually based on achievement of the performance criteria. Management deems it probable that all units will vest; thus, compensation expense was recorded. The issuance of ETP Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of

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ETP Common Units. As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value of expected service period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions.

We assumed a weighted average risk-free interest rate of 3.64%, 2.87% and 0% for the years ended August 31, 2006, 2005 and 2004, respectively, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each employee grant. For the employee awards granted during the years ended August 31, 2006 and 2005, respectively, the grant-date average per unit cash distributions were estimated to be $4.02 and $4.73, respectively. No employee awards were granted during the year ended August 31, 2004.

The following table shows the activity of the awards granted for the years ended August 31, 2006 and 2005:


	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2004	—			—
Awards granted during fiscal year 2005	273,200		$	19.64
Awards vested during fiscal year 2005	—			—
Awards forfeited during fiscal year 2005	(7,600	)		21.10

Unvested awards as of August 31, 2005	265,600			19.60
Awards granted during fiscal year 2006	183,200			31.08
Awards vested during fiscal year 2006	(88,183	)		21.65
Awards forfeited during fiscal year 2006	(2,867	)		21.10

Unvested awards as of August 31, 2006	357,750		$	24.96

The total expected compensation expense to be recognized related to the unvested employee awards as of August 31, 2006 is $2,269 for fiscal year 2007 and $644 for fiscal year 2008.

On September 22, 2006 employee awards of 151,905 units vested and on November 1, 2006, employee awards of 2,334 units vested. Upon vesting, ETP Common Units were issued. Effective September 1, 2006, 397,300 employee awards were granted under the 2004 Unit Plan.

Director Grants

Each ETP Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 ETP Common Units (the “Initial Director’s Grant”). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of ETP Common Units equal to $15 divided by the fair market value of an ETP Common Units on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by ETP’s Compensation Committee.

We assumed a weighted average risk-free interest rate of 3.21%, 2.60% and 2.48% for the years ended August 31, 2006, 2005 and 2004, respectively, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each Director Grant. For the Director Awards granted during the year ended August 31, 2006, 2005 and 2004, respectively, the grant-date average per unit cash distributions were estimated to be $4.11, $3.16, and $2.97, respectively.

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The following table shows the activity of the Director awards granted for the years ended August 31, 2006, 2005 and 2004:


	Number of Units		Weighted Average Fair Value Per Unit
Initial Director’s Grants awarded in fiscal year 2004	12,000		$	18.47

Unvested awards as of August 31, 2004	12,000			18.47

Annual Director’s Grants awarded in fiscal year 2005	4,844			18.49
Awards vested during fiscal year 2005	(3,999	)		19.92

Unvested awards as of August 31, 2005	12,845			18.03

Initial Director Grants awarded in fiscal year 2006	4,000			30.52
Annual Director Grants awarded in fiscal year 2006	2,460			33.23
Awards vested during fiscal year 2006	(2,624	)		19.74
Awards forfeited during fiscal year 2006	(730	)		32.98

Unvested awards as of August 31, 2006	15,951		$	22.54

The total expected compensation expense to be recognized related to the unvested Director Awards as of August 31, 2006 is expected to be $86 for fiscal year 2007 and $21 for fiscal year 2008.

On September 1, 2006, Annual Director Grants of 1,920 units were awarded and 5,693 Director Grants vested and ETP Common Units were issued.

On October 17, 2006, ETP’s Compensation Committee recommended, following its receipt and review of an independent third-party compensation study, and the Board of Directors approved, an amendment to the 2004 Unit Plan to provide that Annual Director’s Grants shall be equal to $25 divided by the fair market value of ETP Common Units on that date. All other Annual Director’s Grants shall be measured at September 1 of each year. On October 17, 2006, 3,240 Annual Director Grants were awarded.

Long-Term Incentive Grants

ETP’s Compensation Committee may, from time to time, grant awards under the Plan to any ETP executive officer or any ETP employee it designates as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of ETP Common Units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of August 31, 2006, there have been no Long-Term Incentive Grants made under the Plan.

Restricted Unit Plan

ETP’s General Partner, Energy Transfer Partners GP, L.P. (“ETP GP”) previously adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan (the “Restricted Unit Plan”), for certain directors and key employees of ETP GP and its affiliates. The Restricted Unit Plan provided rights to acquire up to 292,000 Common Units of ETP. The Restricted Unit Plan provided for the award or grant to key employees of the right to acquire Common Units of ETP on such terms and conditions (including vesting conditions, forfeiture or lapse of rights) as ETP’s Compensation Committee shall determine. In addition, eligible directors automatically received a Director’s Grant of 1,000 ETP Common Units on each September 1, and newly elected directors were also entitled to receive a grant of 2,000 ETP Common Units upon election or appointment to the Board. Directors who were ETP’s employees or employees of ETP GP were not entitled to receive a Director’s Grant of ETP Common Units but could receive ETP Common Units as employees.

Generally, awards granted under the Restricted Unit Plan vested upon the occurrence of specified performance objectives established by ETP’s Compensation Committee at the time designations of grants were made, or if later, the three-year anniversary of the grant date. In the event of a “Change of Control” (as defined in the

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Restricted Unit Plan), all rights to acquire ETP Common Units pursuant to the Restricted Unit Plan immediately vest. Pursuant to the January 2004 acquisition of ETP GP by ETE, the Change of Control provisions of the Restricted Unit Plan were triggered, resulting in the early vesting of 43,200 Heritage units. Individuals holding 9,000 grants waived their rights to early vesting under the Change of Control provisions.

The issuance of ETP Common Units pursuant to the Restricted Unit Plan was intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of ETP’s Common Units. Therefore, no consideration was payable by the plan participants upon vesting and issuance of ETP’s Common Units. Following the June 23, 2004 approval of the 2004 Unit Plan at the special meeting of ETP’s Unitholders, the Restricted Unit Plan was terminated (except for the obligation to issue ETP Common Units at the time the 16,592 grants previously awarded vest), and no additional grants have been or will be made under the Restricted Unit Plan. Previously granted awards of 5,000, 4,333, and 0 vested and ETP Common Units were issued during fiscal years 2006, 2005 and 2004, respectively. On September 1, 2006, 2,333 of these previously granted awards vested.

Long-Term Incentive Plan

Effective September 1, 2000, ETP adopted a Long-Term Incentive Compensation Plan whereby Common Units were to be awarded to the Executive Officers of ETP GP upon achieving certain targeted levels of Distributed Cash (as defined in the Long Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years Distributed Cash per unit. A minimum of 500,000 Common Units on a post-split basis and, if targeted levels were achieved, a maximum of 1,000,000 Common Units were available for award under the Long-Term Incentive Plan. In connection with ETE’s acquisition of ETP GP in January 2004, 300,036 units vested and ETP Common Units were issued, and the Long-Term Incentive Plan was terminated. We did not recognize any compensation expense under the Long-Term Incentive Plan for the years ended August 31, 2006, 2005 or 2004. Compensation expense related to this plan was recognized by Heritage.

8.	INCOME TAXES:

The components of the federal and state income tax provision (benefit) of our taxable subsidiaries are summarized as follows:


	August 31, 2006			August 31, 2005			August 31, 2004
Current provision:
Federal	$	27,640		$	5,042		$	6,505
State		1,987			963			830

Total		29,627			6,005			7,335

Deferred provision (benefit):
Federal		(6,227	)		(2,015	)		(4,366	)
State		(385	)		407			(177	)

Total		(6,612	)		(1,608	)		(4,543	)

Total tax provision before gain on discontinued operations		23,015			4,397			2,792

Gain on discontinued operations:
Current provision:
Federal		—			1,570			—
State		—			259			—

Total		—			1,829			—

Total tax provision	$	23,015		$	6,226		$	2,792

Effective tax rate		5.30	%		1.98	%		0.57	%

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level. The difference between the statutory rate and the effective rate (including taxes related to discontinued operations) is summarized as follows:

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	August 31, 2006		August 31, 2005		August 31, 2004
Federal statutory tax rate	35.00	%	35.00	%	35.00	%
State income tax rate net of federal benefit	3.10	%	3.56	%	3.96	%
Earnings not subject to tax at the Partnership level	(32.80	)%	(36.58	)%	(38.39	)%

Effective tax rate	5.30	%	1.98	%	0.57	%

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred tax liability were as follows:


	August 31, 2006		August 31, 2005
Property, plant and equipment	$	206,460	$	213,829
Other, net		2,046		1,289

Total deferred tax liability	$	208,506	$	215,118

9.	MAJOR CUSTOMERS AND SUPPLIERS:

We had gross sales as a percentage of total revenues to nonaffiliated major customers as follows:


	Year Ended August 31, 2006		Year Ended August 31, 2005		Year Ended August 31, 2004
Midstream and transportation and storage segment:
BP Energy Company	less than 10	%	17.8	%	11.6	%
Houston Pipeline Company	n/a		n/a		11.2	%
Dow Hydrocarbon and Resources, Inc.	less than 10	%	less than 10	%	10.7	%

Our major customers are in the midstream and transportation and storage segments. Our natural gas operations have a concentration of customers in natural gas transmission, distribution and marketing, as well as industrial end-users while our NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively. The Houston Pipeline Company had been one of our major customers prior to our acquisition thereof in fiscal year 2005 (see Note 2). As of August 31, 2005 we had a receivable due from BP Energy Company (“BP”) that was 11% of our total midstream and transportation and storage segment accounts receivable. The receivable from BP was immaterial at August 31, 2006. Management believes that our portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. No single customer accounts for 10% or more of our transportation and storage or propane revenues.

We had gross segment purchases as a percentage of total purchases from major suppliers as follows:


	Year Ended August 31, 2006		Year Ended August 31, 2005		Year Ended August 31, 2004
Midstream and transportation and storage segment:
Unaffiliated
BP Energy Company	less than 10	%	16.0	%	11.0	%
Propane segments (a)
Unaffiliated
Enterprise	27.0	%	23.7	%	22.5	%
Dynegy	less than 10	%	20.6	%	21.8	%
Targa Liquids	18.2	%	less than 10	%	less than 10	%
Affiliated
M.P. Oils, Ltd.	22.0	%	15.4	%	21.0	%

(a)

Fiscal year 2004 purchases from major suppliers in the propane segment represent amounts purchased from January 20, 2004 through August 31, 2004. If the Energy Transfer Transactions had occurred at the beginning of the periods presented, the percentages purchased from Enterprise, Dynegy and MP Oils Ltd. would have been 24.9%, 18.8%, and 19%, respectively, for the year ended August 31, 2004.

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Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010.

These concentrations of suppliers may impact our overall operations either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable us to purchase all of our supply needs at market prices without a material disruption of operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of natural gas, propane and NGLs will be readily available in the future, we expect a sufficient supply to continue to be available.

10.

COMMITMENTS AND CONTINGENCIES:

Commitments

We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these operating leases totaled approximately $18,004, $8,830 and $4,283 for the years ended August 31, 2006, 2005 and 2004, respectively, and has been included in operating expenses in the accompanying statements of operations. Fiscal year future minimum lease commitments for such leases are $8,809 in 2007; $8,889 in 2008; $8,057 in 2009; $7,232 in 2010, $6,557 in 2011 and $9,634 thereafter.

We have forward commodity contracts which are expected to be settled by physical delivery. Short-term contracts which expire in less than one year require delivery of up to 640,796 MMBtu/d. Long-term contracts require delivery of up to 60,356 MMBtu/d and extend through July 2018.

In connection with the acquisition of the ET Fuel System in June of 2004, we entered into an eight-year transportation and storage agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 115.6 billion Btu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. During the third fiscal quarters of 2006 and 2005, we were entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve months ended each May 31st. As a result, we recognized an additional $13,413 and $14,716 in fees during the third fiscal quarters of 2006 and 2005, respectively. TXU Shipper elected to reduce the minimum transport volume to 100 billion Btu per year beginning in January 2006. This change did not have a material impact on our results of operations.

We have signed long-term agreements with several parties committing firm transportation volumes into the East Texas Pipeline. Those commitments include an agreement with XTO Energy Inc. (“XTO”) to deliver approximately 200,000 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational and expires in June 2012.

During 2005, we entered into two new long-term agreements committing firm transportation volumes on certain of our transportation pipelines. The two contracts will require an aggregated capacity of approximately 238,000 MMBtu/d of natural gas and extend through 2011.

In connection with the HPL acquisition in January 2005, we acquired a sales agreement whereby we are committed to sell minimum amounts of gas ranging from 20,000 MMBtu/d to 50,000 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 6.9 billion Bcf for the year ending August 31, 2007.

We also assumed a contract with a service provider which obligated us to obtain certain compression, measurement and other services through 2007 with monthly payments of approximately $1,700. We terminated the measurement portion of this contract subsequent to August 31, 2006 for a payment of approximately $7,000. The remaining compression services total approximately $800 per month through October 2007.

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In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that such terms are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We have also entered into several propane purchase and supply commitments which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We also have a long-term purchase contract for approximately 94 million gallons of propane per year that contains a two-year cancellation provision.

Titan has a long-term purchase contract with Enterprise Products Operating, L.P. to purchase substantially all of its propane requirements. The contract continues until March 31, 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.

Contingencies

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

Litigation

The Operating Partnerships may, from time to time, be involved in litigation and claims arising out of their respective operations in the normal course of business. Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverages and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us and our Operating Partnerships from material expenses related to product liability, personal injury or property damage in the future.

At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.

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Of the pending or threatened matters in which we or our subsidiaries are a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). HOLP received favorable final judgment with respect to the SCANA litigation on all four claims on October 21, 2004, and received $7,700 in net settlement proceeds on June 1, 2006. This amount has been recorded in interest and other income, net in our consolidated statement of operations for the year ended August 31, 2006.

Environmental

Our operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.

In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.

We also assumed certain environmental remediation matters related to eleven sites in connection with our acquisition of HPL.

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Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our August 31, 2006 or our August 31, 2005 balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of August 31, 2006 and 2005, an accrual on an undiscounted basis of $4,387 and $2,036, respectively, was recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors. A receivable of $388 and $404 was recorded in our consolidated balance sheets as of August 31, 2006 and 2005, respectively, to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $21,343 during the period between the remainder of calendar year 2006 to 2008, as well as operating and maintenance costs of $24,850 during that three-year period. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

11.

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily use derivative commodity instruments (futures and swaps) to manage our exposure to fluctuations in margins. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.

130

The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

Non-trading Activities

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. These contracts consist primarily of futures and swaps and are recorded at fair value on the consolidated balance sheets. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occur. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statements of operations. We reclassified into earnings gains of $73,213, losses of $26,784 and gains of $3,396 for the years ended August 31, 2006, 2005 and 2004, respectively, related to commodity financial instruments that were previously reported in OCI.

We expect gains of $2,126 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change. The majority of our commodity-related derivatives are expected to settle within the next two years.

During the second quarter of fiscal year 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 management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring 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 February 2006 through March 2006. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the year ended August 31, 2006, we recognized previously deferred unrealized gains related to February 2006 and March 2006 of $84,680 from the discontinued application of hedge accounting. We classified the $84,680 as a reduction to costs of products sold in our consolidated statements of operations.

In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. In connection with the HPL acquisition, we acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchase and sale contracts, and therefore, are marked to market in addition to the financial options that offset them. The Black-Scholes valuation model was used to estimate the value of these embedded options.

Trading Activities

Trading activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value, and changes in the fair value of these derivative instruments are recognized in midstream and transportation and storage revenue in the consolidated statements of operations on a net basis. Net gains associated with trading activities for the years ended August 31, 2006 and 2005 were $20,115, net of unrealized losses of $25,255, and $50,611, net of unrealized gains of $47,147, respectively. There were no trading activities during the year ended August 31, 2004.

131

Our commodity-related price risk management assets and liabilities as of August 31, 2006 and 2005 were as follows:


August 31, 2006	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	33,711,140		2006-2009	$	(6,247	)
Swing Swaps IFERC	Gas	(37,220,448	)	2006-2008		2,618
Fixed Swaps/Futures	Gas	3,607,500		2006-2007		(170	)
Forward Physical Contracts	Gas	(7,986,000	)	2006-2008		(21,653	)
Options	Gas	(1,046,000	)	2006-2008		21,653
Forwards/Swaps – in Gallons	Propane	24,066,000		2006-2007		199
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(2,572,500	)	2006-2008		21,995
Swing Swaps IFERC	Gas	—		2006		(31	)
Forward Physical Contracts	Gas	(455,000	)	2006		(68	)

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,585,000	)	2006-2007		(2,987	)
Fixed Swaps/Futures	Gas	(37,872,500	)	2006-2007		2,043

August 31, 2005

Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/ NYMEX	Gas	(34,196,114	)	2005-2007		646
Swing Swaps IFERC	Gas	(25,636,504	)	2005-2006		(6,400	)
Fixed Swaps/Futures	Gas	(1,960,000	)	2005-2006		(7,423	)
Options	Gas	(1,776,000	)	2005-2008		78,941
Forward Physical Contracts	Gas	(21,340,000	)	2005-2008		(78,941	)
(Trading)
Basis Swaps IFERC/ NYMEX	Gas	(55,772,500	)	2005-2007		49,833
Swing Swaps IFERC	Gas	(42,204,999	)	2005-2008		(3,686	)
Fixed Swaps/Futures	Gas	(150,000	)	2005		559
Forward Physical Contracts	Gas	—		2005		441

Cash Flow Hedging Derivatives
Fixed Swaps/Futures	Gas	(41,827,500	)	2005-2007		(141,142	)
Fixed Index Swaps	Gas	5,910,000		2005-2006		36,455
Basis Swaps IFERC/ NYMEX	Gas	(6,877,500	)	2005-2006		3,361

Estimates related to our gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. We also attempt to maintain balanced positions in our non-trading activities to protect ourselves from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance our positions. To the extent open commodity positions exist in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

132

Interest Rate Risk

We are exposed to market risk for changes in interest rates related to our bank credit facilities. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements which allow us to effectively convert a portion of variable rate debt into fixed rate debt.

During the years ended August 31, 2006 and 2005, we entered into treasury locks with a notional amount of $200,000 on which we applied hedge accounting under SFAS 133. In June 2006, these treasury locks settled for a gain of $14,237. The gain was recorded as a component of OCI and will be amortized when the hedged debt is issued. We recorded a gain of $573 related to the settlement in interest expense since the first interest payment hedged was no longer probable. Nominal gains and losses were reclassified into earnings previously reported in OCI during the years ended August 31, 2005 and 2004, respectively. Gains of $1,385 were reclassified into earnings previously reported in OCI during the years ended August 31, 2006.

We entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006. We elected to not apply hedge accounting to these financial instruments. Accordingly, changes in the fair value of these instruments are recorded as interest expense on the consolidated statements of operations. The fair value of $629 as of August 31, 2006 related to these treasury locks and interest rate swaps was recorded as a component of price risk management assets in the consolidated balance sheet. In connection with the senior notes issuance described in Note 16, we settled these financial instruments for a gain of $567.

We also entered into forward starting interest swaps with a notional value of $400,000 during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $8,699 on the consolidated balance sheets. They are accounted for as hedges under SFAS 133 and recorded as a component of OCI.

The Parent Company entered into interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006 and had a net fair value of $(404) which was recorded as a component of price risk management assets and liabilities on our consolidated balance sheets. We elected to not apply hedge accounting to these financial instruments.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125,000. The fair value of this swap as of August 31, 2006 was $519 and recorded as a component of price risk management asset on our consolidated balance sheets. We elected to not apply hedge accounting to these financial instruments.

We expect gains of $716 to be reclassified into earnings over the next twelve months related to income on interest rate financial instruments currently reported in OCI. The amount ultimately realized, however, will differ as interest rates change.

ETC OLP also had an interest rate swap with a notional amount of $75,000 that matured in October 2005, and had a fair value of $151 as of August 31, 2005. Under the terms of the swap agreement, we paid a fixed rate of 2.76% and received three-month LIBOR with a quarterly settlement. The interest rate swap was not accounted for as a hedge but received mark to market accounting. Accordingly, changes in the fair value were recorded as a component of interest expense in the consolidated statement of operations.

The following represents gains (losses) on derivative activity for the periods presented before minority interests:


	August 31, 2006			August 31, 2005			August 31, 2004
*Commodity-related*
Change in fair value related to commodity-related derivative activity recognized in revenues and cost of products sold, excluding ineffectiveness	$	(15,625	)	$	30,533		$	2,024
Ineffective portion of derivatives qualifying for hedge accounting recognized in costs of product sold	$	16,701		$	(17,821	)	$	895
Realized gains included in revenues and cost of products sold	$	183,999		$	4,210		$	22,314

*Interest rate swaps*
Change in fair value of interest rate swap included in interest expense, excluding ineffectiveness	$	(128	)	$	690		$	266
Ineffective portion of derivatives qualifying for hedge accounting included in interest expense	$	842		$	(771	)	$	—
Realized gains (losses) on interest rate swap included in interest expense	$	616		$	1,953		$	(1,239	)

133

Credit Risk

We maintain credit policies with regard to our counterparties that we believe significantly minimize our 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. This concentration of counterparties may impact its 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.

12.

RETIREMENT BENEFITS:

ETP sponsors a defined contribution profit sharing and 401(k) savings plan, which covers virtually all employees subject to service period requirements. Profit sharing contributions are made to the plan at the discretion of ETP’s Board of Directors and are allocated to eligible employees as of the last day of the plan year. Employer matching contributions are calculated using a discretionary formula based on employee contributions. We made matching contributions of $5,722, $4,106 and $1,539 to the 401(k) savings plan for the years ended August 31, 2006, 2005 and 2004, respectively.

13.

RELATED PARTY TRANSACTIONS:

Accounts receivable from and accounts payable to related companies relate to normal operating activities and are immaterial at August 31, 2006 and 2005.

As of August 31, 2005 we had a long-term note payable of $1,992 related to our contribution to a propane joint venture entered into July 2005 in which we own a 50% interest. The note was paid during fiscal year 2006.

As of August 31, 2006, we had advances due from the propane joint venture of $3,775 which are included in advances to and investment in affiliates on our consolidated balance sheets.

Our natural gas midstream and transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd. Energy Transfer Group, LLC is the General Partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. We did not acquire the ETG Entities in conjunction with the January 2004 Energy Transfer Transactions. ETP’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of the General Partner, no less favorable than those available from other providers of compression services. During fiscal year 2006, 2005 and 2004, we made payments totaling $2,900, $900 and $279, respectively, to the ETG Entities for compression services provided to and utilized in our natural gas midstream and transportation and storage operations. As of August 31, 2006 and 2005, accounts payable to ETG related to compressor leases were $5 and $102, respectively.

ET GP LLC, an entity controlled by the Co-Chairmen of the Board of Directors of ETE will receive a $500 per year management fee for the management of our operations and activities.

134

On April 28, 2006 ETP entered into a shared services agreement with Energy Transfer Investments, L.P. (“ETI”). Under the terms of the shared services agreement, ETI will reimburse ETP at cost for information technology services, and will pay ETP $36 per year for various other general and administrative services. On the first anniversary of the agreement, we will review the charges, costs and expenses we actually incurred in providing services in order to determine the fee for ensuing periods. Fees recognized since the inception of this agreement were nominal.

14.

REPORTABLE SEGMENTS:

Our financial statements reflect four reportable segments:

ETC OLP:

•

midstream operations

•

transportation and storage operations

HOLP and Titan:

•

retail propane operations

HOLP:

•

wholesale propane operations, including the operations of MP Energy Partnership

Segments below the quantitative thresholds are classified as “other”. None of the components of the “other” segment have ever met any of the quantitative thresholds for determining reportable segments. As a result of the HPL acquisition during fiscal year 2005, management redefined the transportation operations to transportation and storage operations. Management has also combined the domestic wholesale propane and foreign wholesale propane segments into one segment for all periods presented in this report. The combined segment is referred to as the wholesale propane segment.

Midstream and transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income.

The midstream operations focus on the gathering, compression, treating, blending, processing, and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

The transportation and storage operations focus on transporting natural gas through our Oasis Pipeline, ET Fuel System, East Texas Pipeline System, HPL System and Fort Worth Basin Pipeline. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The transportation and storage operations also consist of the HPL System which generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

135

Our retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. We manage our propane segments separately as each segment involves different distribution, sale, and marketing strategies.

We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general, administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit).

Investment in affiliates and equity in earnings (losses) of affiliates relate primarily to our investments in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd., and Mid-Texas which are included in our midstream segment and transportation and storage segment.

The following table presents the financial information by segment for the following periods:


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
Volumes: (unaudited)
Midstream
Natural gas MMBtu/d		1,552,753			1,578,833			1,026,773
NGL bbls/d sold		10,425			12,707			6,920
Transportation and storage
Natural gas MMBtu/d transported		4,633,069			3,495,434			1,090,710
Natural gas MMBtu/d sold		1,580,638			1,361,729			—
Propane gallons (in thousands)
Retail		429,118			406,334			226,209
Wholesale		79,348			70,047			35,719

Total gallons		508,466			476,381			261,928

Revenues:
Midstream	$	4,223,544		$	3,246,772		$	1,880,663
Eliminations		(2,359,256	)		(471,255	)		(27,798	)
Transportation and storage		5,013,224			2,608,108			113,938
Retail propane and other propane related		879,556			709,473			349,344
Wholesale propane		94,288			68,833			27,345
Other		7,740			6,867			3,465

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

Cost of sales:
Midstream	$	4,000,461		$	3,102,539		$	1,787,849
Eliminations		(2,359,256	)		(471,255	)		(27,798	)
Transportation and storage		4,322,217			2,280,082			11,270
Retail propane and other propane related		515,418			403,740			184,371
Wholesale propane		87,337			64,667			24,871
Other		2,139			1,742			861

Total Cost of Sales	$	6,568,316		$	5,381,515		$	1,981,424

Depreciation and amortization:
Midstream	$	19,687		$	17,110		$	12,451
Transportation and storage		50,755			36,020			12,255
Retail propane		58,036			51,487			30,925
Wholesale propane		742			754			432
Other		416			380			179

Total	$	129,636		$	105,751		$	56,242

136


Operating income (loss)
Midstream	$	147,564		$	94,603		$	57,601
Transportation and storage		422,420			151,819			51,470
Retail propane and other propane related		76,055			66,902			27,209
Wholesale propane		1,262			(1,291	)		(812	)
Other		637			608			191
Selling general and administrative expenses not allocated to segments		(72,398	)		(14,720	)		(4,853	)

Total operating income		575,540			297,921			130,806


Other items not allocated by segment:
Interest expense		(150,646	)		(101,061	)		(41,217	)
Loss on extinguishment of debt		(5,060	)		(6,550	)		—
Equity in earnings (losses) of affiliates		(479	)		(376	)		363
Gain (loss) on disposal of assets		851			(330	)		(1,006	)
Gain on Energy Transfer Transactions		—			—			395,253
Interest and other income, net		13,701			12,191			516
Income tax expense		(23,015	)		(4,397	)		(2,792	)
Minority interests		(303,752	)		(96,946	)		(35,164	)

		(468,400	)		(197,469	)		315,953

Income from continuing operations	$	107,140		$	100,452		$	446,759


	August 31,
	2006		2005
Total Assets:
Midstream	$	828,770	$	1,175,029
Transportation and storage		3,317,781		2,586,927
Retail propane and other propane related		1,619,732		1,012,251
Wholesale propane		39,816		27,369
Other		118,042		104,096

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


	Year Ended August 31, 2006		Year Ended August 31, 2005
Additions to property, plant and equipment including acquisitions (accrual basis):
Midstream	$	15,907	$	92,774
Transportation and storage		701,988		959,185
Retail propane and other propane related		263,008		57,421
Wholesale propane		354		191
Other		5,840		1,610

Total	$	987,097	$	1,111,181

15.

QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year under EITF 03-6. Heritage’s and Titan’s businesses are seasonal due to weather conditions in their service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive. ETC OLP’s business is also seasonal due to the operations of ET Fuel Systems and HPL. We expect margin related to HPL operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

137


Fiscal 2006:	Quarter Ended
Fiscal 2006:	November 30		February 28		May 31		August 31			Total Year
Revenues	$	2,416,620	$	2,449,816	$	1,420,335	$	1,572,325		$	7,859,096
Gross Profit		325,993		440,985		272,968		250,834			1,290,780
Operating income		167,866		223,713		115,377		68,584			575,540
Net income		39,601		24,435		43,271		(167	)		107,140
Limited Partners’ interest in net income		39,353		24,291		43,052		(165	)		106,531
Basic net income per limited partner unit	$	0.29	$	0.18	$	0.32	$	—		$	0.80
Diluted net income per limited partner unit	$	0.29	$	0.18	$	0.31	$	—		$	0.79

	Quarter Ended
Fiscal 2005:	November 30		February 28		May 31		August 31			Total Year
Revenues	$	864,198	$	1,439,844	$	2,031,749	$	1,833,007		$	6,168,798
Gross Profit		136,293		228,669		214,751		207,570			787,283
Operating income		42,295		117,182		75,426		63,018			297,921
Net income		14,368		38,858		79,818		13,702			146,746
Limited Partners’ interest in net income		14,276		38,610		79,037		13,616			145,539
Basic net income per limited partner unit	$	0.13	$	0.37	$	0.75	$	0.10		$	1.30
Diluted net income per limited partner unit	$	0.11	$	0.29	$	0.60	$	0.09		$	1.09

The results of operations for the fourth quarter of fiscal year 2006 were significantly affected by litigation and contingency provisions and the loss from the Titan operations subsequent to its acquisition date.

See Note 2 for discussion on the sale of our Elk City System during the third quarter of fiscal year 2005 for which we realized a gain on sale of discontinued operations of $44,013, net of income taxes and minority interest.

In the second quarter of fiscal year 2006, we recognized $84,680 of income from the discontinued application of hedge accounting before income taxes and minority interest (see Note 11).

16.

SUPPLEMENTAL INFORMATION:

Following are the financial statements of the Parent Company which are included to provide additional information with respect to the Parent Company’s financial position. results of operations and cash flows on a stand-alone basis:

138

BALANCE SHEETS

(in thousands, except unit data)


	August 31, 2006			August 31, 2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	135		$	8,527
Accounts receivable from related parties		752			889
Price risk management assets		711			—
Prepaid and other		301			747

Total current assets		1,899			10,163

ADVANCES TO AND INVESTMENT IN AFFILIATES		663,245			501,939
INTANGIBLES AND OTHER ASSETS, net		3,344			5,932

Total assets		668,488			518,034

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable		386			35
Accounts payable to affiliate		736			180
Accrued interest		4,105			5,931
Accrued and other current liabilities		104			25

Total current liabilities		5,331			6,171

LONG-TERM DEBT, net of current maturities		616,291			600,000
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		1,115			—

		622,737			606,171

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL (DEFICIT):
General Partner		(69	)		772
Common Unitholders (124,360,520 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)		(9,586	)		—
Class B Unitholders (2,521,570 and 0 units authorized, issued and outstanding at August 31, 2006 and 2005, respectively)		53,130			—
Limited partners’ deficit (0 and 136,357,870 limited partner units issued and outstanding at August 31, 2006 and 2005, respectively)		—			(62,216	)

		43,475			(61,444	)

Accumulated other comprehensive income (loss) of equity investee		2,276			(26,693	)

Total partners’ capital (deficit)		45,751			(88,137	)

Total liabilities and partners’ capital (deficit)	$	668,488		$	518,034

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STATEMENTS OF OPERATIONS

(in thousands)


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(55,374	)	$	(1,051	)	$	(805	)

OTHER INCOME (EXPENSE):
Equity in earnings of affiliates		204,987			141,260			55,602
Interest expense		(36,773	)		(9,529	)		—
Loss on extinguishment of debt		(5,060	)		—			—
Gain on Energy Transfer Transactions		—			—			395,253
Other, net		(638	)		16,066			167

INCOME BEFORE INCOME TAXES		107,142			146,746			450,217
Income tax expense		(2	)		—			—

NET INCOME		107,140			146,746			450,217

GENERAL PARTNER’S INTEREST IN NET INCOME		609			1,207			4,438

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	106,531		$	145,539		$	445,779

140

STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended August 31, 2006			Year Ended August 31, 2005			Year Ended August 31, 2004
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	110,554		$	91,619		$	228,751

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			—			(30,000	)
Cash invested in subsidiaries		(135,088	)		(7,886	)		(22,231	)
Proceeds from sale of investments		—			2,632			88,906

Net cash provided by (used in) investing activities		(135,088	)		(5,254	)		36,675

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		666,058			600,000			—
Principal payments on debt		(649,575	)		—			—
Equity offering		473,978			—			—
Redemption of Common Units in IPO		(131,620	)		—			—
Repurchase of Common Units		(237,817	)		—			—
Cash distributions to Partners		(101,259	)		(671,612	)		(266,275	)
Debt issuance costs		(3,623	)		(6,281	)		—
Retirement of employee incentive units		—			(1,046	)		—

Net cash provided by (used for) financing activities		16,142			(78,939	)		(266,275	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(8,392	)		7,426			(849	)

CASH AND CASH EQUIVALENTS, beginning of period		8,527			1,101			1,950

CASH AND CASH EQUIVALENTS, end of period	$	135		$	8,527		$	1,101

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17.

SUBSEQUENT EVENTS:

On November 1, 2006, ETP issued approximately 26.1 million of its Class G Units to us for $1,200,000, 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 us pursuant to a customary agreement, and we have been granted registration rights. ETP used the proceeds of $1,200,000 to fund a portion of the Transwestern Pipeline acquisition and to repay indebtedness ETP incurred in connection with the Titan acquisition as discussed above. The terms of the Class G Units are substantially similar to those of ETP’s previous Class F Units, as discussed in Note 7 above.

On November 1, 2006, the Parent Company entered into a First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006 which provided for an additional six year $1,300,000 Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.

In a separate but related transaction, ETE acquired, from ETI, the remaining 50% Class B limited partner interests in ETP GP, which resulted in ETE now owning 100% of the IDRs of ETP. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units and the assumption by ETE of approximately $70,500 of ETI’s indebtedness. The Class C Units have essentially the same voting rights and rights to distributions as the Common Units and Class B Units. The Class C Units are convertible into Common Units upon approval by the ETE Common Unitholders. The Partnership plans to file the required proxy as soon as practicable upon the completion of one year as a public company in February 2007.

On September 15, 2006, ETP announced that it had entered into agreements with GE Energy Financial Services and Southern Union Company to acquire the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. The agreements provide for a series of transactions in which we will acquire all of the member interests in CCE Holdings, LLC (“CCEH”) owned by GE Energy Financial Services and certain other investors. The member interests acquired will represent a 50% ownership in CCEH, which was formed in 2004 to purchase CrossCountry Energy. In the second transaction, CCEH will redeem ETP’s 50% ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”), following which Southern Union will own all of the member interests of CCEH. On November 1, 2006 ETP acquired the member interests in CCEH from GE and certain other investors for $1,000,000 and expects to complete the remaining series of transactions in the second quarter of fiscal year 2007. Upon closing, ETP expects the transaction to be immediately accretive to its Unitholders. ETP financed the purchase price with its issuance of approximately 26.1 million Class G Units issued to the Parent Company simultaneous with the closing on November 1, 2006.

On October 23, 2006, ETP closed the issuance of $400,000 of 6.125% senior notes due 2017 and $400,000 of 6.625% senior notes due 2036. Net proceeds from the issuance of debt were approximately $791,000. ETP used the proceeds to pay borrowings and accrued interest under its revolving credit agreement. Interest on the notes will be due semiannually and will accrue from October 23, 2006. The notes are unsecured senior obligations and will be fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. These notes were sold under ETP’s S-3 Registration Statement which provides for the sale of a combination of limited partner interests and debt totaling $1,500,000.

18.

SUBSEQUENT PRIVATE PLACEMENT OF UNITS

On November 28, 2006, we sold 7,789,133 of our 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 $213,500 before expenses. We granted registration rights to the investors. We plan to use the proceeds to repay indebtedness under our credit facility.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. An evaluation was performed under the supervision and with the participation of our management, including the Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of August 31, 2006 to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realties that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving its desired control objectives.

In accordance with SEC Regulations regarding the reporting of Internal Controls over Financial Reporting, our management is not required to provide an annual report regarding internal controls over our financial reporting because we are not considered an accelerated filer because we have not completed 12 calendar months of operations. The report for the year ending August 31, 2007 will include management’s assessment of the effectiveness of our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Partnership Management

LE GP LLC (the “General Partner”) is our General Partner. The General Partner manages and directs all of our activities. Our officers and directors are officers and directors of LE GP LLC. The members of our General Partner elect our General Partner’s Board of Directors. The board of directors of our General Partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our General Partner. Pursuant to other authority, the board of directors of our General Partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement. All of the current directors of our General Partner also serve as directors of the General Partner of ETP.

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Corporate Governance

The Board of Directors of our General Partner has adopted both a Code of Business Conduct applicable to our Directors, Officers and Employees, and Corporate Governance Guidelines for Directors and the Board. Current copies of our Code of Business Conduct, Corporate Governance Guidelines and charters applicable to the committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.

Annual Certification

The Parent Company has filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to this report. Our President provided to the New York Stock Exchange the initial CEO certification regarding our compliance with the New York Stock Exchange’s corporate governance listing standards within the time specified by the NYSE for companies listing in conjunction with their initial public offering.

Conflicts Committee

Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Parent Company and our Common Unitholders. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company, approved by all partners of the Parent Company and not a breach by the General Partner or its Board of Directors of any duties they may owe the Parent Company or the Common Unitholders.

Audit Committee

The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 401 of Regulation S-K. The Board has determined that based on relevant experience, Audit Committee member Paul E. Glaske qualified as an Audit Committee financial expert during the Parent Company’s 2006 fiscal year. A description of the qualifications of Mr. Glaske may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by SAS 61, Communications with Audit Committees, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Board of Directors adopts the Charter for the Audit Committee. On May 3, 2006 and within the timeframe of our IPO specified for establishment of an independent Audit Committee by NYSE corporate governance standards, John D. Harkey, Jr., Paul E. Glaske and Bill W. Byrne were elected as members of the Audit Committee. Mr. Harkey was elected Chair of the Committee. Mr. Harkey currently serves as a member or chairman of the audit committee of four other publicly traded companies, in addition to his service as a member of the Audit Committee of our General Partner and the Audit Committee of the General Partner of ETP. As required by Rule 303A.07 of the NYSE Listed Company Manual, the Board of Directors of our General Partner has determined that such simultaneous service does not impair Mr. Harkey’s ability to effectively serve on our Audit Committee.

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Compensation and Nominating/Corporate Governance Committees

We are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership.

Code of Business Conduct

The Board of Directors has adopted a Code of Business Conduct applicable to our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our General Partner. The Code of Business Conduct is available on our website at www.energytransfer.com and in print to any Unitholder that requests it. Amendments to, or waivers from, the Code of Business Conduct will also be available on our website and reported as may be required under SEC rules, however, any technical, administrative or other non-substantive amendments to the Code of Business Conduct may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.

Meetings of Non-management Directors and Communications with Directors

Our non-management Directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.

The Parent Company has established a procedure by which Unitholders and interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the Parent Company’s independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aube at Energy Transfer Equity, L.P., 2928 Woodside Street, Dallas, TX, 75204. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Directors and Executive Officers of the General Partner

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors as of October 16, 2006. Executive officers and directors are elected for indefinite terms.


Name	Age	Position with General Partner
John W. McReynolds	55	Director, President and Chief Financial Officer of our General Partner

Ray C. Davis	64	Director and Co-Chairman of the Board of our General Partner

Kelcy L. Warren	50	Director and Co-Chairman of the Board of our General Partner

Kenneth A. Hersh	43	Director of our General Partner

David R. Albin	47	Director of our General Partner

K. Rick Turner	48	Director of our General Partner

Bill W. Byrne	76	Director of our General Partner

Paul E. Glaske	73	Director of our General Partner

John D. Harkey, Jr	46	Director of our General Partner

H. Michael Krimbill	53	Director of our General Partner

Set forth below is biographical information regarding the foregoing officers and directors of our General Partner:

145

John W. McReynolds. Mr. McReynolds has served as our President since March 2005 and served as a Director and Chief Financial Officer since August 2005. He is also a director of Energy Transfer Partners. Prior to becoming President of Energy Transfer Equity, Mr. McReynolds was a partner with the international law firm of Hunton & Williams LLP, for over 20 years. As a lawyer, he specialized in energy-related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation and governmental proceedings, including as an expert in special projects for boards of directors of public companies.

Ray C. Davis. Mr. Davis was appointed Co-Chairman of the Board of Directors of our General Partner, LE GP, LLC, effective upon the closing of our IPO. Mr. Davis also serves as Co-Chief Executive Officer and Co-Chairman of the Board of Directors of the General Partner of ETP and has served in that capacity since the combination of the midstream and transportation operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Davis also serves as Co-Chief Executive Officer of the General Partner of ETC OLP, and as Co-Chief Executive Officer of ETP and Co-Chairman of the Board of the General Partner of ETE, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Davis served as Vice President of the General Partner of ET Company I, Ltd., the entity that operated ETC OLP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the Board of Directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more than 31 years of business experience in the energy industry.

Kelcy L. Warren. Mr. Warren was appointed Co-Chairman of the Board of Directors of our General Partner, LE GP, LLC, effective upon the closing of our IPO. Mr. Warren also serves as Co-Chief Executive Officer and Co-Chairman of the Board of the General Partner of ETP and has served in that capacity since the combination of the midstream and transportation operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Warren also serves as Co-Chief Executive Officer of the General Partner of ETC OLP, and as Co-Chief Executive Officer of ETP and Co-Chairman of the Board of the General Partner of ETE, positions he has held since their formation in 2002. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the General Partner of ET Company I, Ltd. the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.

David R. Albin. Mr. Albin is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1988. Prior to his participation as a founding member of Natural Gas Partners, L.P. in 1988, he was a partner in the $600 million Bass Investment Limited Partnership. Prior to joining Bass Investment Limited Partnership, he was a member of the oil and gas group in the investment banking division of Goldman, Sachs & Co. He currently serves as a Director of NGP Capital Resources Company. Mr. Albin has served as a Director of Energy Transfer Partners GP since February 2004 and has served as a Director of our General Partner since October 2002.

Kenneth A. Hersh. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. He currently serves as a director of NGP Capital Resources Company. Mr. Hersh has served as a director of Energy Transfer Partners GP since February 2004 and has served as a director of our General Partner since October 2002.

K. Rick Turner. Mr. Turner has been employed by Stephens’ family entities since 1983. He is currently Senior Managing Principal of The Stephens Group, LLC. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries, and power technology. Mr. Turner currently serves as a director of Atlantic Oil Corporation; SmartSignal Corporation; JV Industrials, LLC, JEBCO Seismic, LLC; North American Energy Partners Inc., Seminole Energy Services, LLC, BTEC Turbines LP, and the General Partner of Energy Transfer Partners, LP (“ETP”). Prior to joining Stephens, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing Certified Public Accountant. Mr. Turner has served as a director of our General Partner since October 2002.

146

Bill W. Byrne. Mr. Byrne is the principal of Byrne & Associates, LLC, an investment company based in Tulsa, Oklahoma. Prior to his retirement in 1992, Mr. Byrne was Vice President of Warren Petroleum Company, the gas liquids division of Chevron Corporation, serving in that capacity from 1982 to 1992. Mr. Byrne has served as a director of ETP’s General Partner since 1992 and is a member of both the Audit Committee and the Compensation Committee of ETP’s General Partner. Mr. Byrne is a former president and director of the National Propane Gas Association (NPGA). Mr. Byrne has served as a director of our General Partner since May 2006.

Paul E. Glaske. Mr. Glaske retired as Chairman and Chief Executive Officer of Blue Bird Corporation, the largest manufacturer of school buses with manufacturing plants in three countries. Prior to becoming president of Blue Bird in 1986, Mr. Glaske served as the president of the Marathon LeTourneau Company, a manufacturer of large off-road mining and material handling equipment and off-shore drilling rigs. He currently is a member of the board of directors of BorgWarner, Inc., of Chicago, Illinois where he serves as chair of the governance committee. In addition, Mr. Glaske serves on the board of directors of both Lincoln Educational Services in New Jersey, and Camcraft, Inc., in Illinois. Mr. Glaske has served as a director of ETP’s General Partner since February 2004 and is chairman of ETP’s Audit Committee and a member of ETP’s Independent Committee. Mr. Glaske has served as a director of our General Partner since May 2006.

John D. Harkey, Jr. Mr. Harkey has served as Chief Executive Officer and Chairman of Consolidated Restaurant Companies, Inc., and as Chief Executive Officer and Vice Chairman of Consolidated Restaurant Operations Inc. since 1998. Mr. Harkey currently serves on the Board of Directors and Audit Committee of Leap Wireless International, Inc., Emisphere Technologies, Inc., Pizza Inn, and Loral Space & Communications, Inc. He also serves on the Executive Board of Circle Ten Council of the Boy Scouts of America. Mr. Harkey has served as a director of our General Partner since December 2005. In May 2006, Mr. Harkey was elected as a director of our General Partner and member of the Audit Committee.

H. Michael Krimbill. Mr. Krimbill is the President and Chief Financial Officer of ETP’s General Partner, and has served in these capacities since January 2004. Mr. Krimbill joined Heritage as Vice President and Chief Financial Officer in 1990. He served as President of Heritage from April 1999 to January 2004 and as President and Chief Executive Officer of Heritage from March 2000 to January 2004. Mr. Krimbill has served as a director of ETP’s General Partner since August 2000 and our General Partner since his election in March 2006.

Compensation of the General Partner

LE GP does not receive any management fee or other compensation in connection with its management of the Parent Company.

Compliance with Section 16(a) of the Securities and Exchange Act

Section 16(a) of the Securities and Exchange Act of 1934 requires our officers and directors, and persons who own more than 10% of a registered class of our equity securities, to file reports of beneficial ownership and changes in beneficial ownership with the Securities and Exchange Commission (“SEC”). Officers, directors and greater than 10% Unitholders are required by SEC regulations to furnish the General Partner with copies of all Section 16(a) forms.

Based solely on our review of the copies of such forms received by us, or written representations from certain reporting persons that no Forms 5 were required for those persons, we believe that during fiscal year ending August 31, 2006, all filing requirements applicable to its officers, directors, and greater than 10% beneficial owners were met in a timely manner.

ITEM 11. EXECUTIVE COMPENSATION

We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by LE GP and its executive officers.

147

Summary Compensation Table

The following table sets forth the annual salary, bonus and all other compensation awards and payouts for each of the past three fiscal years earned by: (i) all persons serving as the Chief Executive Officer of LE GP during fiscal year 2006; (ii) the four next highly compensated executive officers other than the Chief Executive Officer, who served as executive officers of LE GP during fiscal year 2006 and (iii) any persons who would have been reported had they been an executive officer of our LE GP at the end of fiscal year 2006.


Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation	All Other Compensation
John W. McReynolds	2006	$	350,000	$	175,000	—	(2	)
President and Chief	2005	$	350,000		—	—	—
Financial Officer (1)	2004		—		—	—	—

(1)	Mr. McReynolds was named President in March 2005 and Chief Financial Officer in August 2005. Mr. McReynolds’ salary is presented on an annualized basis. Mr. McReynolds is our only executive officer.

(2)

In conjunction with the closing of the Parent Company’s IPO in February 2006, the Parent Company issued 2,521,570 Class B Units with a value of $52.9 million to FEM Group, LP which was recorded as compensation expense in our consolidated statement of operations for the year ended August 31, 2006. Mr. McReynolds controls, and currently owns 100% of, FEM Group, LP.

Energy Transfer Equity Long-Term Incentive Plan

We have adopted the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our General Partner and its affiliates who perform services for us. The long-term incentive plan consists of the following five components: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to 3 million units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the board of directors of our General Partner.

The Board of Directors of our General Partner or a Compensation Committee of the board may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our Board of Directors or a Compensation Committee of the Board also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as may be required by the exchange upon which ETE’s Common Units are listed at that time, if any. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The plan will expire upon the earlier of the 10^th anniversary of its adoption by the General Partner, its termination by the Board of Directors or the compensation committee or when no units remain available under the plan for awards. Awards then outstanding will continue pursuant to the terms of their grants.

Restricted Units. A restricted unit is a Common Unit that vests over a period of time and that during such time is subject to forfeiture. In the future, the compensation committee may determine to make grants of restricted units under the plan to employees, directors and consultants containing such terms as the compensation committee determines. The compensation committee will determine the period over which restricted units granted to participants will vest. The compensation committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units will vest upon a change in control, as defined in the plan. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted unit. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

148

Common Units to be delivered as restricted units may be Common Units acquired by us in the open market, Common Units acquired by us from any other person or any combination of the foregoing. If we issue new Common Units upon the grant of the restricted units, the total number of Common Units outstanding will increase.

We intend the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our Common Units. Therefore, plan participants will not pay any consideration for the Common Units they receive, and we will receive no remuneration for the units.

Phantom Units. A phantom unit entitles the grantee to receive a Common Unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a Common Unit. In the future, the compensation committee may determine to make grants of phantom units under the plan to employees, consultants and directors containing such terms as the compensation committee determines. The compensation committee will determine the period over which phantom units granted to participants will vest. The committee, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the phantom units will vest upon a change in control. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the compensation committee or the terms of the award agreement provide otherwise.

Common Units to be delivered upon the vesting of phantom units may be Common Units acquired by us in the open market, Common Units acquired by us from any other person or any combination of the foregoing. If we issue new Common Units upon vesting of the phantom units, the total number of Common Units outstanding will increase.

We intend the issuance of any Common Units upon vesting of the phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our Common Units. Therefore, plan participants will not pay any consideration for the Common Units they receive, and we will receive no remuneration for the units.

Unit Options. The long-term incentive plan will permit the grant of options covering Common Units. The compensation committee may make grants under the plan to employees, consultants and directors containing such terms as the committee determines. Unit options will have an exercise price that may be greater or less than the fair market value of the units on the date of grant, in the discretion of the compensation committee. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, the unit options will become exercisable upon a change in control. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the option agreement or the compensation committee provides otherwise.

Upon exercise of a unit option, we will issue new Common Units, acquire Common Units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee’s discretion. If we issue new Common Units upon exercise of the unit options (or a unit appreciation right settled in Common Units), the total number of Common Units outstanding will increase. The availability of unit options is intended to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common Unitholders.

Unit Appreciation Rights. The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in Common Units or, in the discretion of the compensation committee, in cash. Initially, we do not expect to grant unit appreciation rights under our long-term incentive plan. In the future, the compensation committee may determine to make grants of unit appreciation rights under the plan to employees and members of our board of directors containing such terms as the committee determines. Unit appreciation rights will have an exercise price that may be greater or less than the fair market value of the Common Units on the date of grant, in the discretion of the compensation committee. In general, unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit appreciation rights will become exercisable upon a change in control. If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s unvested unit appreciation rights will be automatically forfeited unless, and to the extent, the grant agreement or compensation committee provides otherwise.

149

Upon exercise of a unit appreciation right settled in Common Units, we will issue new Common Units, acquire Common Units on the open market or directly from any person or use any combination of the foregoing, in the compensation committee’s discretion. If we issue new Common Units upon exercise of the unit appreciation right settled in Common Units, the total number of Common Units outstanding will increase. The availability of unit appreciation rights is intended to furnish additional compensation to employees, consultants and members of our board of directors and to align their economic interests with those of common Unitholders.

Distribution Equivalent Rights. The compensation committee may, in its discretion, grant distribution equivalent rights (“DERs”) with respect to awards other than restricted units. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the Award is outstanding. Payment of a DER may be subject to the same vesting terms as the award to which it relates.

Class B Units. Our Long-Term Incentive Plan also provided for the grant of 2,521,570 Class B Units pursuant to the terms of our Partnership Agreement to a limited partnership for which Mr. McReynolds is the sole limited partner and an entity owned and controlled by Mr. McReynolds is the general partner. This partnership may in the future issue additional interests to other persons. Whether such issuances are made and the terms of any such issuances of interests will be determined by Mr. McReynolds.

Each Class B unit represents a limited partner interest in us and is entitled to receive quarterly cash distributions in the same amount as the quarterly cash distributions we make on each Common Unit. Each Class B Unit is allocated a portion of our income, gain, loss, deduction and credit in a pro rata basis with each Common Unit, and each Class B Unit is entitled to receive distributions upon liquidation in the same manner as each Common Unit. Each Class B unit will also have the same voting rights as a Common Unit from and after the time that the Class B Units are entitled to be converted into Common Units. Pursuant to the terms of the Class B Units, each Class B Unit became convertible into one Common Unit at the election of the holder of the Class B Unit at any time after August 2006, the six month anniversary of the completion of our IPO. The Class B units are not subject to vesting.

Compensation of Directors

During fiscal 2006, LE GP paid no compensation to members of its board of directors for their service as directors. No additional remuneration will be paid to officers or employees of our General Partner who also serve as directors. Each independent director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees and may from time to time be compensated for service on any special conflicts committee. Each director will be fully indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law. Further, our General Partner has entered into indemnity agreements with each of its directors.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Equity Compensation Plan Information

At the time of our IPO, we adopted the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our general partner and its affiliates who perform services for us. The long-term incentive plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to three million units, excluding the Class B Units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the compensation committee of the board of directors of our General Partner.

150

The following table sets forth in tabular format, a summary of our equity plan information:


Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders:
Equity compensation plans not approved by security holders:	—		—	3,000,000

Total		$		3,000,000

The following table sets forth certain information as of November 15, 2006, regarding the beneficial ownership of our securities by certain beneficial owners, all directors and named executive officers of the General Partner of our General Partner, each of the named executive officers and all directors and executive officers of the General Partner of our General Partner as a group, of our Common Units, Class B Units and Class C Units. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.


Title of Class	Name and Address of Beneficial Owner (1)	Beneficially Owned (2)	Percent of Class
Common Units
	Ray C. Davis (7)	71,400	*
	Kelcy L. Warren (7)	128,500	*
	H. Michael Krimbill (3)	1,550,135	1.25	%
	Bill W. Byrne	23,800	*
	David R. Albin (4)	—	*
	John D. Harkey Jr.	15,000	*
	Kenneth A. Hersh (4)	—	*
	Paul E. Glaske	21,500	*
	K. Rick Turner (4)	82,840	*
	John McReynolds (6)	2,521,570	1.99	%
	Natural Gas Partners VI, L.P. (7)(8)	—	*
	ETC Holdings, LP (7)	70,600,963	56.77	%
	All Directors and Executive Officers as a group (10 persons)	4,414,745	3.48	%
Class B Units	FEM Group, LP (5)	2,521,570	100	%
Class C Units	Energy Transfer Investments, LP (9)	83,148,900	100	%

*	Less than one percent (1%)

(1)

The address for Mr. McReynolds, FEM Group, LP and Energy Transfer Investments, LP is 2828 Woodside Street, Dallas, Texas 75204. The address for Messrs. Davis and Warren is 2838 Woodside Street, Dallas, Texas 75204. The address for Mr. Krimbill is 8801 S. Yale Avenue, Suite 310, Tulsa, Oklahoma 74137. The address for Messrs. Albin and Hersh is 125 E. John Carpenter Freeway, Suit 600, Irving, Texas 75062. The address for Messrs. Byrne, Glaske, Harkey, Albin and Turner is 2838 Woodside Street, Dallas, Texas 75204.

(2)

Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Securities Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof (“Voting Power”) or to dispose or direct the disposition thereof (“Investment Power”) or has the right to acquire either of those powers within sixty (60) days.

(3)	Mr. Krimbill shares Voting and Investment Power on a portion of his units with his spouse.

151

(4)	Each of Messrs. Albin, Hersh and Turner are representatives of or owners in entities owning interests in ETE and may be deemed to beneficially own such limited partnership interests of ETE, although no such deemed ownership is depicted in this table.

(5)	FEM Group, LP is owned by Mr. McReynolds who may be deemed to beneficially own the limited partner interests held by FEM Group, LP to the extent of his respective interests therein.

(6)

Consists of 2,521,570 Class B Units, which may be converted into Common Units, held by FEM Group, LP, to the extent of Mr. McReynolds’ interest therein. Mr. McReynolds also has an indirect interest in Energy Transfer Investments, LP, which owns Class C Units, and may be deemed to beneficially own, and may in the future receive distributions of units from, units owned by such entity. Such beneficial ownership is not depicted in this table.

(7)

Messrs. Davis and Warren and the NGP Fund are the sole members of ET GP, LP, which is the sole general partner of ETC Holdings, LP. Therefore, each of Messrs. Davis and Warren and the NGP Fund may be deemed to have beneficial ownership of the Common Units owned by ETC Holdings to the extent of their ownership interests therein. ETC Holdings also has an ownership interest in Energy Transfer Investments, LP.

(8)

G.F.W. Energy VI L.P. and GFW VI, L.L.C. may be deemed to beneficially own the Common Units owned of record by the NGP Fund, by virtue of GFW VI, L.L.C. being the sole general partner of G.F.W. Energy VI L.P. G.F.W. Energy VI, L.P. being the sole general partner of the NGP Fund. Messrs. Hersh and Albin, who constitute a majority of the members of GFW VI, L.L.C., may also be deemed to share power to vote or to direct the vote and to dispose or to direct the disposition of, the Common Units.

(9)	Messrs. Davis, Warren, Krimbill and McReynolds and the NGP Fund hold indirect interests in Energy Transfer Investments, LP and may be deemed to beneficially own, and may in the future receive distributions from, units owned by such entity. Such beneficial ownership is not depicted in this table.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

After the Parent Company’s acquisition of the remaining 50% of the ETP incentive distribution rights on November 1, 2006 as discussed above, the Parent Company owns 100% of the Class A and Class B Limited Partner interests, and 100% of the General Partner interests in Energy Transfer Partners GP, L.P., the General Partner of ETP. The Parent Company’s cash flows currently consist of distributions from ETP related to the following partnership interests, including incentive distribution rights in ETP:

•

our ownership of the 2% General Partner interest in ETP, which we hold through our ownership interests in ETP GP;

•

62.5 million ETP Units (including Class G Units we acquired on November 1, 2006 as discussed above), representing approximately 43% of the total outstanding ETP Units, which we hold directly; and

•

100% of the incentive distribution rights in ETP, which we likewise hold through our ownership interests in ETP GP and which entitle us to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases.

ETP is required by its Partnership Agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its General Partner. Based on ETP’s quarterly distribution of $0.75 per unit for the three months ended August 31, 2006 and the number of its Common Units outstanding at November 1, 2006, the Parent Company would be entitled to receive a quarterly cash distribution of $99.5 million (or $397.9 million on an annualized basis), which consists of $3.2 million from our indirect ownership of the 2% General Partner interest in ETP, $49.4 million from our indirect ownership of 100% of the incentive distribution rights in ETP and $46.9 million from the Common and Class G Units of ETP that we currently own.

All of the current directors of LE GP, the Parent Company’s general partner, are also directors of the general partner of ETP. In addition, Messrs. Davis, Warren and Krimbill are also executive officers of the general partner of ETP.

152

ET GP LLC, an entity controlled by Messrs. Davis and Warren and the NGP Fund will receive a $0.5 million per year management fee for the management of our operations and activities. Under the terms of a shared services agreement, ETE will also pay ETP an annual administrative fee of $0.5 million for the provision of various general and administrative services for ETE’s benefit.

Our natural gas midstream operations secure compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the General Partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by us in conjunction with the January 2004 Energy Transfer Transactions. ETP’s Co-Chief Executive Officers, Ray C. Davis and Kelcy L. Warren have an indirect ownership interest in and one of ETP’s directors, Ted Collins, Jr., has an ownership interest in the ETG Entities. In addition, Ted Collins, Jr. and our President and Chief Financial Officer, John W. McReynolds, serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are negotiated at an arms-length basis by management and are reviewed and approved by ETP’s Audit Committee. During fiscal years August 31, 2006 and 2005, payments totaling $2.9 million and $0.9 million, respectively, were made to the ETG Entities for compression services provided to and utilized in our natural gas midstream operations.

Under the terms of a Shared Services Agreement entered into in connection with the Energy Transfer Transactions, the ETG Entities lease office space and obtain related services from ETP. Payments totaling $0.2 million were paid by the ETG Entities during the fiscal year ended August 31, 2006.

In connection with the HPL acquisition, ETC OLP entered into a short-term loan agreement with us whereby ETC OLP borrowed $174.6 million to acquire the working inventory of natural gas stored in the Bammel storage facilities with interest based on the Eurodollar Rate plus 3.0% per annum. ETC OLP also incurred $3.1 million in debt issuance costs associated with the loan agreement. The loan was paid in full during the year ended August 31, 2005. We are also the owner of ETP’s General Partner. ETP’s Co-Chief Executive Officers serve as Co-Chairmen of the Board of Directors of our General Partner, and John W. McReynolds, our President, Chief Financial Officer and Director of our General Partner, LE GP, LLC also serves as a Director of ETP’s General Partner. In addition, Messrs. Davis, Warren, Krimbill, Albin, Hersh, Turner, McReynolds, McCrea, Burk, and Atkinson, and Ms. Hicks, each an officer and/or director of ETP’s General Partner, directly or indirectly own interests in us.

At August 31, 2005, our natural gas midstream subsidiaries owned a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by an entity that is owned in part by Ted Collins, Jr., one of ETP’s General Partner’s directors. ETC OLP is the operator of the Dorado System. At August 31, 2004, there was a balance of $0.2 million owing to us by the entity that is owned in part by Mr. Collins for services provided as operator, which was paid in full during the year ended August 31, 2005. In November 2005, we acquired the remaining interest in South Texas Gas Gathering for $0.7 million.

During the fiscal year ended August 31, 2005, payments of approximately $1.1 million were made to the law firm of Hunton & Williams for legal services rendered. These services were provided to ETC OLP and ETP in connection with the Energy Transfer Transactions in January of 2004, the acquisition of the HPL System, and for the representation of ETC OLP in other matters. John W. McReynolds, the President, Chief Financial Officer and Director of the Parent Company’s General Partner since August 2004, was a partner in the Dallas, Texas office of Hunton & Williams until March 2005.

In June 2005, ETP completed the sale of 1,640,000 ETP Common Units to a group of its executive managers including the President, Vice-President and General Counsel, and Vice-President-Corporate Development. The units were sold at a price of $31.95 per Common Unit, which represented a 6% discount to the closing Common Unit price on June 17, 2005. The price received was based on the fair market value and we believe is comparable to the price that ETP would have received from an unaffiliated purchaser in a large block equity transaction. The transaction was approved by both the special committee of independent directors and the audit committee of ETP’s General Partner.

153

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended August 31, 2006 and 2005:


	Year Ended August 31,
	2006		2005
Audit fees (1)	$	3,884,139	$	4,210,587
Audit related fees (2)		5,000		5,000
Tax fees (3)		—		—
All other fees (4)		—		—

Total	$	3,889,139	$	4,215,587

(1)

Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the Securities and Exchange Commission and services related to the audit of the internal controls over financial reporting of our subsidiary, Energy Transfer Partners, L.P.

(2)	Includes fees related to consultations concerning financial accounting and reporting standards and work paper access.

(3)	Includes fees related to professional services for tax compliance, tax advice, and tax planning.

(4)	Consists of fees for services other than services reported above.

Pursuant to the charter of the Audit Committee, they are responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Committee.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

•

the auditors’ internal quality-control procedures;

•

any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

•

the independence of the external auditors;

•

the aggregate fees billed by our external auditors for each of the previous two fiscal years; and

•

the rotation of the lead partner.

154

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following documents are filed as a part of this Report:

(1)

Financial Statements - see Index to Financial Statements appearing on page 82.

(2)

Financial Statement Schedules - None.

(3)

Exhibits - see Index to Exhibits set forth on page E-1.

155

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	ENERGY TRANSFER EQUITY, L.P.

	By:	LE GP, L.L.C.,
		its General Partner

Date: November 29, 2006	By:	/s/ John W. McReynolds
		John W. McReynolds
		President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:


Signature	Title	Date
/s/ John W. McReynolds	President and Chief Financial Officer	November 29, 2006
John W. McReynolds	(Principal Executive, Financial and Accounting Officer)

/s/ Ray C. Davis	Director and Co-Chairman of the Board	November 29, 2006
Ray C. Davis

/s/ Kelcy L. Warren	Director and Co-Chairman of the Board	November 29, 2006
Kelcy L. Warren

/s/ David R. Albin	Director	November 29, 2006
David R. Albin

/s/ Bill W. Byrne	Director	November 29, 2006
Bill W. Byrne

/s/ Paul E. Glaske	Director	November 29, 2006
Paul E. Glaske

/s/ John D. Harkey	Director	November 29, 2006
John D. Harkey

/s/ Kenneth A. Hersh	Director	November 29, 2006
Kenneth A. Hersh

/s/ H. Michael Krimbill	Director	November 29, 2006
H. Michael Krimbill

/s/ K. Rick Turner	Director	November 29, 2006
K. Rick Turner

156

INDEX TO EXHIBITS

The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
3.1	333-128097	3.1	Certificate of Conversion of Energy Transfer Company, L.P.

3.2	333-128097	3.2	Certificate of Limited Partnership of Energy Transfer Equity, L.P.

3.3	333-128097	3.3	Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.3.1			Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.4	333-128097	3.4	Certificate of Conversion of LE GP, LLC.

3.5	333-128097	3.5	Certificate of Formation of LE GP, LLC.

3.6	333-128097	3.6	Limited Liability Company Agreement of LE GP, LLC.

3.7	333-04018	3.1	Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P. (now known as Energy Transfer Partners, L.P.)

3.7.1	1-11727 (8-K) (8/23/00)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.2	1-11727 (10K) (8/31/01)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.3	1-11727 (10-Q) (5/31/02)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.4	1-11727 (10-Q) (5/31/02)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.5	1-11727 (10-Q) (2/29/04)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.6	1-11727 (10-Q) (2/29/04)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

3.7.7	1-11727 (8-K) (3/16/05)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.7.8	1-11727 (8-K) (2/9/06)	3.1.8	Amendment No. 8 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.7.9	1-11727 (8-K) (5/3/06)	3.1.9	Amendment No. 9 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.7.10	1-11727 (8-K) (11/3/06)	3.1.10	Amendment No. 10 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.8	333-04018	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

E-1


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
3.8.1	1-11727 (10-K) (8/31/00)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.2	1-11727 (10-Q) (5/31/02)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.3	1-11727 (10-Q) (2/29/04)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P. (22)

3.9	1-11727 (10-Q) (2/29/04)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

3.10	1-11727 (10-Q) 2/28/02)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

3.11	333-128097	3.11	Second Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C.

3.12	333-128097	3.12	Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.

3.13	333-128097	3.13	Certificate of Formation of Energy Transfer Partners, L.L.C.

3.13.1	333-128097	3.13.1	Certificate of Amendment of Energy Transfer Partners, L.L.C.

3.14	333-128097	3.14	Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.

4.1	1-11727 (8-K) (1/19/05)	4.1	Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

4.2	1-11727 (8-K) (1/19/05)	4.2	First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

4.3	1-11727 (10-Q) (2/28/05)	10.45	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005.

4.4	1-11727 (10-Q) (2/28/05)	10.46	Notation of Guaranty.

4.5	1-11727 (8-K) (1/19/05)	4.3	Registration Rights Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto.

4.6	1-11727 (10-Q) (2/28/05)	10.39.1	Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.

4.7	1-11727 (8-K) (8/2/05)	4.1	Third Supplemental Indenture dated July 29, 2005, to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and Wachovia Bank, National Association, as trustee.

E-2


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
4.8	1-11727 (8-K) (8/2/05)	4.2	Registration Rights Agreement dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and the initial purchasers party thereto.

4.9	1-11727 (10-K/A) (8/31/05)	4.9	Form of Senior Indenture of Energy Transfer Partners, L.P.

4.10	1-11727 (10-K/A) (8/31/05)	4.10	Form of Subordinated Indenture of Energy Transfer Partners, L.P.

4.11	1-11727 (10-K) (8/31/06)	4.13	Fourth Supplemental Indenture dated as of June 29, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

4.12	1-11727 (8-K) (10/25/06)	4.1	Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

10.1	1-11727 (Sch. 13D/A) (6/24/05)	99.F	Credit and Guaranty Agreement dated as of June 16, 2005 among Energy Transfer Company, L.P., the guarantors named therein, various lenders, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, Citicorp North America, Inc., as syndication agent, Lehman Commercial Paper Inc., as documentation agent, and Goldman Sachs Credit Partners L.P., Citigroup Markets Inc. and Lehman Brothers Inc., as lead arrangers and lead bookrunners.

10.2	333-04018	10.2	Form of Note Purchase Agreement (June 25, 1996).

10.2.1	1-11727 (10-Q) (11/30/96)	10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.

10.2.2	1-11727 (10-Q) (2/28/97)	10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.

10.2.3	1-11727 (10-K) (8/31/98)	10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.

10.2.4	1-11727 (10-K) (8/31/99)	10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.

10.2.5	1-11727 (10-Q) (5/31/00)	10.16.3	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

10.2.6	1-11727 (8-K) (8/23/00)	10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

10.2.7	1-11727 (10-Q) (2/28/01)	10.2.7	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

E-3


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.2.8	1-11727 (10-Q) (2/29/04)	10.2.8	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

10.3	333-04018	10.3	Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P.

10.4.1**	1-11727 (10-Q) (2/28/02)	10.6.3	Heritage Propane Partners, L.P. (now known as Energy Transfer Partners, L.P.) Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.

10.4.2**	1-11727 (Sch. 14A) (5/18/04)	Annex A	Energy Transfer Partners 2004 Unit Plan.

10.4.3**	1-11727 (8-K) (11/1/04)	10.1	Form of Grant Agreement.

10.5	1-11727 (10-Q) (5/31/98)	10.16	Note Purchase Agreement of Heritage Operating, L.P. dated as of November 19, 1997.

10.5.1	1-11727 (10-K) (8/31/98)	10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement of Heritage Operating, L.P.

10.5.2	1-11727 (10-K) (8/31/98)	10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.3	1-11727 (10-Q) (5/31/00)	10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.4	1-11727 (8-K) ((8/23/00)	10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.5	1-11727 (10-Q) (2/28/01)	10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.5.6	1-11727 (10-Q) (2/29/04)	10.16.6	Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.6	1-11727 (8-K) (8/23/00)	10.17	Contribution Agreement dated June 15, 2000, among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.

10.6.1	1-11727 (8-K) (8/23/00)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.

E-4


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.7	1-11727 (8-K) (8/23/00)	10.18	Subscription Agreement dated June 15, 2000, between Heritage Propane Partners, L.P. and individual investors.

10.7.1	1-11727 (8-K) (8/23/00)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.

10.7.2	1-11727 (10-K) (8/31/01)	10.18.2	Amendment Agreement dated January 5, 2001 to the June 15, 2000 Subscription Agreement.

10.7.3	1-11727 (10-Q) (11/30/01)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.

10.8	1-11727 (10-K) (8/31/01)	10.19	Note Purchase Agreement of Heritage Operating, L.P. dated as of August 10, 2000.

10.8.1	1-11727 (10-Q) (2/28/01)	10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.8.2	1-11727 (10-Q) (5/31/01)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.8.3	1-11727 (10-Q) (2/29/04)	10.16.6	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.9	1-11727 (10-Q) (2/28/02)	10.26	Assignment, Conveyance and Assumption Agreement dated as of February 4, 2002, between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P.

10.10	1-11727 (10-Q) (2/28/02)	10.27	Assignment, Conveyance and Assumption Agreement dated as of February 4, 2002, between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P.

10.11	1-11727 (8-K) (1/6/03)	10.28	Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002, among V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P.

10.12	1-11727 (10-K) (8/31/03)	10.30	Acquisition Agreement dated November 6, 2003, among the owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and LaGrange Energy, L.P.

10.13	1-11727 (10-K) (8/31/03)	10.31	Contribution Agreement dated November 6, 2003, among LaGrange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

10.13.1	1-11727 (10-Q) (11/30/03)	10.31.1	Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003, among LaGrange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

E-5


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.14	1-11727 (10-K) (8/31/03)	10.32	Stock Purchase Agreement dated November 6, 2003, among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.

10.15	1-11727 (8-K) (6/14/04)	10.35	Purchase and Sale Agreement dated April 25, 2004, between TXU Fuel Company and Energy Transfer Partners, L.P.

10.15.1	1-11727 (8-K) (6/14/04)	10.35.1	First Amendment to Purchase and Sale Agreement and Closing Agreement dated June 1, 2004, between TXU Fuel Company and Energy Transfer Partners, L.P.

10.16	1-11727 (10-Q) (5/31/04)	10.36	Third Amended and Restated Credit Agreement dated March 31, 2004, among Heritage Operating L.P. and the Banks.

10.17	1-11727 (8-K) (1/19/05)	10.1	Credit Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, and other lenders party thereto.

10.17.1	1-11727 (10-Q) (2/28/05)	10.40.1	First Amendment to Credit Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, and other lenders party thereto.

10.18	1-11727 (8-K) (1/19/05)	10.2	Guaranty dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders.

10.18.1	1-11727 (10-Q) (2/28/05)	10.41.1	Guaranty Supplement dated February 24, 2005.

10.19	1-11727 (8-K) (2/1/05)	10.1	Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and LaGrange Acquisition, L.P., as Buyer.

10.20	1-11727 (8-K) (2/1/05)	10.2	Cushion Gas Litigation Agreement dated January 26, 2005, among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and LaGrange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies.

10.21	1-11727 (8-K/A) (3/17/05)	10.3	Loan Agreement dated as of January 26, 2005, between LaGrange Acquisition, L.P., as Borrower, and LaGrange Energy, L.P., as Lender.

10.22	1-11727 (8-K) (2/4/02)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.

E-6


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.23	1-11727 (10-Q) (2/29/04)	4.2	Unitholder Rights Agreement dated January 20, 2004, among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and LaGrange Energy, L.P.

10.24	333-128097	10.24	Registration Rights Agreement for Limited Partnership Units of LaGrange Energy, L.P.

10.25**	333-128097	10.25	Energy Transfer Equity Long-Term Incentive Plan.

10.26**	333-128097	10.26	Form of Director and Officer Indemnification Agreement.

10.27	1-11727 (8-K) (12/16/05)	10.1	Credit Agreement dated December 12, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citibank, N.A., as co-syndication agents, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, Credit Suisse, Deutsche Bank AG and UBS Loan Finance LLC, as senior managing agents, Fortis Capital Corp, Suntrust Bank and Wells Fargo Bank, N.A., as managing agents, and other lenders party thereto.

10.28	1-11727 (8-K) (12/16/05)	10.2	Guaranty, effective as of December 13, 2005, by the subsidiary guarantors thereto in favor of Wachovia Bank, National Association, as administrative agent for the Lenders.

10.29	1-32740 (8-K) (2/8/06)	10.2	Credit Agreement dated February 8, 2006, between Energy Transfer Equity, L.P. and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citicorp North America, Inc., as co-syndication agents, BNP Paribas and The Royal Bank of Scotland plc New York Branch, as co-documentation agents, Credit Suisse Cayman Islands Branch, Deutsche Bank AG New York Branch and UBS Loan Finance LLC, as senior managing agents, and Fortis Capital Corp, Suntrust Bank and Wells Fargo Bank, N.A., as managing agents.

10.30	333-128097	10.30	Shared Services Agreement dated as of August 26, 2005, among Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.

10.31	1-11727 (10Q) (5/31/06)	10.48	Credit Agreement dated as of May 31, 2006, among Energy Transfer Partners, L.P., as the Borrower, Credit Suisse, Cayman Islands Branch as administrative agent, and the other lenders party hereto, Credit Suisse Securities (USA) LLC and Banc of America Securities, LLC, as joint lead arrangers and co-documentation and syndication agents.

E-7


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.32	1-11727 (10Q)(5/31/06)	10.49	Amended and Restated Credit Agreement dated as of June 29, 2006, among Energy Transfer Partners, L.P., as the Borrower, Wachovia Bank, National Association as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citibank, N.A. as co-syndication agents, BNP Paribas and The Royal Bank of Scotland, plc, as co-documentation agents, Deutsche Bank Securities, Inc., Credit Suisse, Cayman Islands Branch, UBS Securities, LLC, JPMorgan Chase Bank, N.A. and Suntrust Bank as senior managing agents and the other lenders party hereto Wachovia Capital Markets, LLC as sole lead arranger and sole book manager.

10.33	1-11727 (10Q)(5/31/06)	10.50	Guarantee for the Amended and Restated Credit Agreement dated as of June 29, 2006.

10.34			First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006, among Energy Transfer Equity, L.P., as the borrower, Wachovia Bank, National Association as administrative agent, UBS Loan Finance LLC, as syndication agent, BNP Paribas, Citicorp North America, Inc. and JPMorgan Chase Bank, N.A. as co-documentation agents, and UBS Securities LLC and Wachovia Capital Markets, LLC, as joint lead arrangers and joint book managers.

10.35			Contribution and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Partners, L.P.

10.36			Contribution, Assumption and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Investments, L.P.

10.37	1-11727 (8-K) (11/3/06)	3.1.10	Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.

10.38			Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P.

10.39	1-11727 (8-K) (9/18/06)	10.1	Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.) Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holding I LLC.

10.40	1-11727 (8-K) (9/18/06)	10.2	Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC.

10.41	1-11727 (8-K) (9/18/06)	10.3	Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company.

E-8


Exhibit Number	Previously Filed *
	With File Number (Form) (Period Ending or Date)	As Exhibit
10.42	1-11727 (10-K) (8/31/06)	10.54	Fourth Amended and Restated Credit Agreement dated as of August 31, 2006 between and among Heritage Operating L.P., as the Borrower, and the Banks now or hereafter signatory parties hereto, as lenders “Banks” and Bank of Oklahoma, National Association as administrative agent and joint lead arranger for the Banks, JPMorgan Chase Bank, N.A., as syndication agent for the Banks, and J.P. Morgan Securities Inc., as joint lead arranger for the Banks.

21.1			List of Subsidiaries.

31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1			Financial Statements of LE GP, L.L.C. as of August 31, 2006

E-9

Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership

Exhibit 3.3.1

AMENDMENT NO. 1

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

ENERGY TRANSFER EQUITY, L.P.

This Amendment No. 1 (this “Amendment”) to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., a Delaware limited partnership (the “Partnership”), dated as of February 8, 2006 (the “Partnership Agreement”), is entered into effective as of November 1, 2006, by LE GP, LLC, a Delaware limited liability company (the “General Partner”), as the general partner of the Partnership, on behalf of itself and the Limited Partners of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS

WHEREAS, Section 5.8 of the Partnership Agreement provides that the General Partner, without the approval of any Limited Partner except as otherwise provided in the Partnership Agreement, may, for any Partnership purpose, at any time or from time to time, issue additional Partnership Securities for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion; and

WHEREAS, Section 13.1(d)(i) of the Partnership Agreement provides that the General Partner, without the approval of any Partner, may amend any provision of the Partnership Agreement (to reflect a change that, in the discretion of the General Partner, does not adversely affect the Unitholders in any material respect); and

WHEREAS, Section 13.1(g) of the Partnership Agreement provides that the General Partner, without the approval of any Partner (subject to Section 5.9 of the Partnership Agreement), may amend any provision of the Partnership Agreement to reflect an amendment that, in the discretion of the General Partner, is necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.8 of the Partnership Agreement; and

WHEREAS, the Partnership has entered into a Contribution and Conveyance Agreement, dated as of November 1, 2006 (the “Contribution Agreement”), between the Partnership and Energy Transfer Investments, L.P., a Delaware limited partnership (“ETI”), pursuant to which ETI will contribute to the Partnership the 50% Class B limited partner interest in Energy Transfer Partners GP, L.P. owned by ETI in exchange for a new class of Partnership Securities to be designated as “Class C Units” with such terms as are set forth in this Amendment; and

WHEREAS, the General Partner has determined that the creation of the Class C Units will be in the best interests of the Partnership and beneficial to the Limited Partners, including the holders of the Common Units; and

WHEREAS, the issuance of the Class C Units complies with the requirements of the Partnership Agreement; and

WHEREAS, the General Partner has determined, pursuant to Section 13.1(j) of the Partnership Agreement, that the amendments to the Partnership Agreement set forth herein are necessary or appropriate in connection with the authorization of the issuance of the Class C Units; and

NOW, THEREFORE, the Partnership Agreement is hereby amended as follows:

Section 1. Amendments.

(a) Section 1.1 is hereby amended to add or amend and restate the following definitions:

“Class C Distribution Increase Date” has the meaning assigned to such term in Section 5.12(g).

“Class C Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and Assignees, and having the rights and obligations specified with respect to the Class C Units in this Agreement. The term “Class C Unit” does not refer to a Common Unit prior to the conversion of a Class C Unit into a Common Unit pursuant to the terms hereof.

“Conversion Approval” has the meaning assigned to such term in Section 5.12(f).

“Conversion Approval Date” has the meaning assigned to such term in Section 5.12(f).

“Conversion Effective Date” has the meaning assigned to such term in Section 5.12(h).

“Excess Payment” has the meaning set forth in Section 5.12(g).

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Offering” means the initial public offering and sale of Common Units to the public in February 2006.

“Initial Unit Price” means with respect to the Common Units and the Class G Units, the initial public offering price per Common Unit at which the Common Units were sold to the public in the Initial Offering.

“Issue Price” means the price at which a Unit is purchased from the Partnership, after taking into account any sales commission or underwriting discount charged to the Partnership and after taking into account any other form of discount with respect to the price at which a Unit is purchased from the Partnership.

“Remaining Net Positive Adjustments” means, as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Class C Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units, Class B Units or Class C Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period and (ii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period.

“Share of Additional Book Basis Derivative Items” means, in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Class C Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time and (ii) with respect to the General Partner (as holder of the General Partner Interest), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the limitation in the foregoing proviso shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) if the General Partner shall have notified such Person or Group in writing, prior to such acquisition, that such limitation shall not apply to such Person or Group or (iii) to any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner; and provided, further, that none of

the Class C Units shall be deemed to be Outstanding for purposes of determining if any Class C Units are entitled to distributions of Available Cash unless such Class C Units shall have been reflected on the books of the Partnership as outstanding during such Quarter and on the Record Date for the determination of any distribution of Available Cash.

“Unrecovered Capital” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

(b) Section 1.1 of the Partnership Agreement is hereby further amended to amend and restate the final sentence of the definition of “Common Unit” as follows:

“The term “Common Unit” does not refer to a Class C Unit prior to its conversion into a Common Unit pursuant to the terms hereof.”

“(c) The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.4(b). The transfer of a Class C Unit shall be subject to the restrictions imposed by Section 6.5.”

(d) Article V is hereby amended to add a new Section 5.12 creating a new series of Units as follows:

“Section 5.12 Establishment of Class C Units.

(a) General. The General Partner hereby designates and creates a class of Units to be designated as “Class C Units” and consisting of a total of 83,148,900 Class C Units, and fixes the designations, preferences and relative, participating, optional or other special rights, powers and duties of holders of the Class C Units as set forth in this Section 5.12.

(b) Rights of Class C Units. During the period commencing upon issuance of the Class C Units and ending on the Conversion Effective Date (or that later time specified in this Section 5.12(b)), unless amended pursuant to Section 5.12(i) hereof:

(i) Allocations. Except as otherwise provided in this Agreement, all items of Partnership income, gain, loss, deduction and credit shall be allocated to the Class C Units to the same extent as such items would be so allocated if such Class C Units were Common Units that were then Outstanding.

(ii) Distributions. Except as otherwise provided in this Agreement, the Class C Units shall have the right to share in partnership distributions on a pro rata basis with the Common Units, so that the amount of any Partnership distribution to each Common Unit will equal the amount of such distribution to each Class C Unit; provided, however, in the event that the Partnership would not have available cash with respect to any Quarter sufficient to distribute $0.175 (the “Initial Quarterly Distribution Amount”) in respect of each Common Unit, Class B Unit and Class C Unit or there shall exist in respect of any Quarter, a Cumulative Common Unit Arrearage, then Available Cash with respect to such Quarter shall, subject to Section 17–607 of the Delaware Act, be distributed as follows:

(A) First, to the Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until there has been distributed in respect of each Common Unit and Class B Unit then outstanding an amount equal to the Initial Quarterly Distribution Amount for such Quarter;

(B) Second, to the Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until there has been distributed in respect of each Common Unit and Class B Unit then outstanding an amount equal to the Cumulative Common Unit Arrearage;

(C) Third, to the Unitholders holding Class C Units and to the General Partner, in proportion to their respective Percentage Interests.

The following definitions shall be applied to the terms used in this Section 5.12(b):

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter ending on or prior to the Conversion Effective Date as to which distributions are made pursuant to the proviso to Section 5.12(b)(ii), the excess, if any, of (a) the Initial Quarterly Distribution Amount with respect to such Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to such Common Unit in respect of such quarter pursuant to clause (A) of the proviso to Section 5.12(b)(ii).

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage for each of the Quarters ending on or prior to the

Conversion Effective Date over (b) the sum of any distributions theretofore made pursuant to clause (B) of the proviso to Section 5.12(b)(ii).

(c) Voting Rights. The Class C Units will have such voting rights pursuant to the Partnership Agreement as such Class C Units would have if they were Common Units that were then Outstanding, except that (i) with respect to Conversion Approval, none of the Class C Units shall be deemed Outstanding as of the record date for such vote or be entitled to vote thereon and (ii) other than with respect to Conversion Approval, the Class C Units shall be entitled to vote as a separate class on any matter that adversely affects the rights or preferences of the Class C Units in relation to other classes of Partnership Interests or as required by law. The approval of a majority of the Class C Units shall be required to approve any matter for which the holders of the Class C Units are entitled to vote as a separate class. Each Class C Unit will be entitled to the number of votes equal to the number of Common Units into which a Class C Unit is convertible at the time of the record date for the vote or written consent on the matter.

(d) Certificates. The Class C Units will be evidenced by certificates in substantially the form of Exhibit A to this Amendment, subject to the satisfaction of any applicable legal and regulatory requirements, may be assigned or transferred in a manner identical to the assignment and transfer of other Units. The certificates will initially include a restrictive legend to the effect that the Class C Units have not been registered under the Securities Act or any state securities laws.

(e) Registrar and Transfer Agent. The General Partner will act as registrar and transfer agent of the Class C Units.

(f) Conversion. Except as provided in Section 5.12(i) and in this Section 5.12(f), the Class C Units are not convertible into Common Units. The Partnership shall, pursuant to the Contribution Agreement, take such actions as may be necessary or appropriate to submit to a vote or consent of the Unitholders (other than holders of Class C Units) the approval of a change in the terms of the Class C Units to provide that each Class C Unit shall automatically convert into one Common Unit (subject to appropriate adjustment in the event of any split-up, combination or similar event affecting the Common Units that occurs prior to the conversion of the Class C Units) effective immediately upon receipt of such approval from such Unitholders (the “Conversion Approval”) without any further action by the holders thereof. The vote or consent required for the Conversion Approval will be the requisite vote required under the rules or staff interpretations of the National Securities Exchange on which the Common Units are listed or admitted for trading. The date that Conversion Approval is obtained is herein referred to as the “Conversion Approval Date.” Upon receipt of the Conversion Approval and compliance with Section 5.12(h), the terms of the Class C Units will be changed, automatically and without further action, on the Conversion

Effective Date (as defined in Section 5.12(h) below), so that each Class C Unit is converted into one Common Unit and, immediately thereafter, none of the Class C Units shall be Outstanding.

(g) Automatic Provisions. If the Conversion Effective Date has not occurred within 180 days following the date of issuance of the Class C Units, then, effective as of the next succeeding day (the “Class C Distribution Increase Date”) until the Conversion Effective Date, Section 5.12(b) will be deemed to be amended in its entirety, automatically and without further action, as follows:

(b) Rights of Class C Units. Prior to the Conversion Effective Date (or the later date specified in this Section 5.12(b)):

(i) Allocations. All allocations of items of Partnership income, gain, loss, deduction and credit shall be allocated to the Class C Units based on 115% of that which would be allocated to the Common Units so that the amount thereof allocated to each Class C Unit will be 115% of the amount thereof allocated to each Common Unit, and the allocations to Class C Units shall have the same order of priority relative to allocations on the Common Units.

(ii) Distributions. The Class C Units shall have the right to share in Partnership distributions based on 115% of the amount of any Partnership distribution that would be made to each Common Unit so that the amount of any Partnership distribution to each Class C Unit will equal 115% of the amount of such distribution to each Common Unit, and the right of holders of Class C Units to receive distributions shall have the same order of priority relative to distributions on the Common Units.

(iii) Liquidating Distributions. The Class C Units shall have rights upon dissolution and liquidation of the Partnership, including the right to share in any liquidating distributions, that are based on 115% of the liquidating distributions that would be made to the Common Units so that the amount of any liquidating distribution to each Class C Unit will equal 115% of the amount of such distribution to each Common Unit, and the rights of the Class C Units upon dissolution and liquidation of the Partnership shall have the same order of priority relative to the rights of the Common Units.

(iv) Excess Payments. If the Conversion Effective Date occurs after the Class C Distribution Increase Date, on the Conversion Effective Date (or the later date specified as follows), then for the Quarter in which such conversion occurs, concurrently with the distribution of Available Cash in respect of such Quarter in accordance with Section 6.3 hereof (subject to this

Section 5.12), a distribution shall be paid to each holder of record of Class C Units as of the Conversion Effective Date, with the amount of such distribution for each such Class C Unit to be equal to the product of (a) 15% of the amount to be distributed in respect of such Quarter to each Common Unit times (b) a fraction, of which (I) the numerator is the number of days in such Quarter up to but excluding the Conversion Effective Date and (II) the denominator is the total number of days in such Quarter (such amount, the “Excess Payment”). For the taxable year in which an Excess Payment is made, if not previously allocated, each holder of a Class C Unit shall be allocated items of gross income in an amount equal to the Excess Payment distributed to it as provided in Section 6.1(d)(xiii). For the avoidance of doubt, each Common Unit issued upon conversion of a Class C Unit shall be entitled to receive the full distribution payable to the holder of a Common Unit concurrently with the distribution of such Excess Payment.”

(h) Surrender of Certificates. Upon receipt of the Conversion Approval in accordance with Section 5.12(f) or a change in rules of the National Securities Exchange as described in Section 5.12(i), the General Partner shall give the holders of the Class C Units prompt notice of such Conversion Approval or change in rules and, subject to the requirements of Section 6.5, each holder of Class C Units shall promptly surrender the Class C Unit Certificates therefor, duly endorsed, at the office of the General Partner or of any transfer agent for the Class C Units. In the case of any such conversion, the Partnership shall, as soon as practicable thereafter, issue and deliver at such office to such holder of Class C Units one or more Common Unit Certificates, registered in the name of such holder, for the number of Common Units to which such holder shall be entitled. Such conversion shall be deemed to have been made as of the third calendar day following the Conversion Approval Date or, in the case of Section 5.12(i), the date of the effectiveness of such rule change (the “Conversion Effective Date”), and the Person entitled to receive the Common Units issuable upon such conversion shall be treated for all purposes as the record holder of such Common Units as of such date.

(i) Change in Rules of National Securities Exchange. If at any time (i) the rules of the National Securities Exchange on which the Common Units are listed or admitted to trading or the staff interpretations of such rules are changed or (ii) facts or circumstances arise so that no vote or consent of Unitholders is required as a condition to the listing or admission to trading of the Common Units that would be issued upon any conversion of any Class C Units into Common Units as provided in Section 5.12(f), the terms of such Class C Units will be changed so that each Class C Unit is converted (without further action or any vote of any Unitholders other than compliance with Section 5.12(h)) into one Common Unit and, immediately thereafter, none of the Class C Units shall be Outstanding.”

(e) Section 6.1(c)(i) is amended and restated as follows:

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.6(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

Second, to all Unitholders holding Common Units and Class B Units and to the General Partner, in proportion to their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital plus (2) the Initial Quarterly Distribution Amount for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to clause (A) of the proviso to Section 5.12(b)(ii) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid IQD”); plus (3) any then existing Cumulative Common Unit Arrearage;

Third, if such net Termination Gain is recognized (or is deemed to be recognized) prior to the Conversion Effective Date, to all Unitholders holding Class C Units and to the General Partner, in proportion to their respective Percentage Interests, until the Capital Account in respect of each Class C Unit then Outstanding equals the sum of (1) its Unrecovered Capital, determined for the taxable year (or portion thereof) to which this allocation of gain relates, plus (2) the Initial Quarterly Distribution Amount for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to clause (C) of the proviso to Section 5.12(b)(ii) with respect to such Class C Unit for such Quarter;

Fourth, to all Unitholders and to the General Partner, in accordance with their relative Percentage Interests.

(f) Section 6.1(d)(ix) is amended and restated as follows:

“(xi) Economic Uniformity. (A) With respect to any taxable period ending upon, or after, the date a Conversion Notice is given by a holder of Class B Units pursuant to Section 5.7, items of Partnership income and gain shall be allocated 100% to each Partner holding such Class B Units until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each converted Class B Unit to an amount equal to the product of (1) the number of converted Class B Units and (2) the Per Unit Capital Amount for a Common Unit. The purpose for this allocation is to establish uniformity between the Capital Accounts underlying converted Class B Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of Class B Units into Common Units.

(B) At the election of the General Partner with respect to any taxable period ending upon the Conversion Effective Date, all or a portion of the remaining items of Partnership income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(ix)(A), shall be allocated 100% to each Partner holding such Common Units resulting from the conversion pursuant to Section 5.12 in the proportion of the number of converted Class C Units held by such Partner to the total number of converted Class C Units then Outstanding, until each such Partner has been allocated an amount of Partnership income or gain that increases the Capital Account maintained with respect to each converted Class C Units to an amount equal to the product of (A) the number of converted Class C Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying converted Class C Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such converted Class C Units into Common Units.”

(g) Article VI is hereby amended to add a new Section 6.1(d)(xiii) as follows:

“(xiii) Priority Allocations. If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed or deemed distributed pursuant to Section 5.6(a), with respect to Class C Units, or Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) each Unitholder receiving such greater cash or property distribution shall be allocated gross income and gain in an amount equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated gross income and gain in an aggregate amount equal to

the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs, times (bb) the sum of the amounts allocated in clause (1) above by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs.”

(h) Article VI is hereby amended to add a new Section 6.5 as follows:

“Section 6.5 Special Provisions Relating to the Holders of Class C Units. A Unitholder holding a Class C Unit that has converted into a Common Unit pursuant to Section 5.12 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Units until such time as the General Partner determines, based on advice of counsel, that the converted Class C Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.5, the General Partner shall take whatever steps are required to provide economic uniformity to the converted Class C Units in preparation for a transfer of such Units, including the application of Section 6.1(d)(ix)(B); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units represented by Common Unit Certificates.”

Section 2. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

Section 4. Counterparts. This Amendment may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.

IN WITNESS WHEREOF, this Amendment has been executed as of the date first written above.


GENERAL PARTNER:

LE GP, LLC

By:		/s/ John W. McReynolds
		John W. McReynolds, President

LIMITED PARTNERS:

All Limited Partners now and hereafter admitted as limited partners of the Partnership, pursuant to Powers of Attorney now and hereafter executed in favor of, and granted and delivered to, the General Partner.

By: LE GP, LLC, General Partner of
Energy Transfer Equity, L.P., as attorney-in-fact for all Limited Partners pursuant to the powers of Attorney granted pursuant to Section 2.6 of the Partnership Agreement.

By:		/s/ John W. McReynolds
		John W. McReynolds, President

SIGNATURE PAGE TO

AMENDMENT NO. 1

THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

ENERGY TRANSFER EQUITY, L.P.

EXHIBIT A

Certificate Evidencing Class C Units

Representing Limited Partner Interests in

Energy Transfer Equity, L.P.


No.		Class C Units

In accordance with Section 4.1 of the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), Energy Transfer Equity, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that (the “Holder”) is the registered owner of Class C Units representing limited partner interests in the Partnership (the “Class C Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Class C Units represented by this Certificate. The rights, preferences and limitations of the Class C Units are set forth in, and this Certificate and the Class C Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2828 Woodside Street, Dallas, Texas 75204. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED. IT MAY NOT BE SOLD, OFFERED FOR SALE, PLEDGED OR HYPOTHECATED IN THE ABSENCE OF A REGISTRATION STATEMENT IN EFFECT WITH RESPECT TO THE SECURITIES UNDER SUCH ACT OR AN OPINION OF COUNSEL SATISFACTORY TO THE PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF ENERGY TRANSFER EQUITY, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF ENERGY TRANSFER EQUITY, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE ENERGY TRANSFER EQUITY,

A-1

L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LE GP, LLC, THE GENERAL PARTNER OF ENERGY TRANSFER EQUITY, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ENERGY TRANSFER EQUITY, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.


Dated:		Energy Transfer Equity, L.P.

Countersigned and Registered by:		By:	LE GP, LLC,
			its General Partner

		By:

as Transfer Agent and Registrar		Name:

By:		By:
	Authorized Signature		Secretary

[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM -	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT
TEN ENT -	as tenants by the entireties	Custodian
		(Cust) (Minor)
JT TEN -	as joint tenants with right of	under Uniform Gifts/Transfers to CD
	survivorship and not as	Minors Act (State)
	tenants in common

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto

(Please print or typewrite name

and address of Assignee)

(Please insert Social Security or other

identifying number of Assignee)

Class C Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint

A-2

as its attorney-in-fact with full power of substitution to transfer the same on the books of Energy Transfer Equity, L.P.

Date:

NOTE:

The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.

THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15

(Signature)

No transfer of the Class C Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Class C Units to be transferred is surrendered for registration or transfer and, following a FERC Notice, an Application for Transfer of Class C Units has been properly completed and executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge. A transferor of the Class C Units shall have no duty to the transferee with respect to execution of the Application for Transfer of Class C Units in order for such transferee to obtain registration of the transfer of the Class C Units.

A-3

First Amendment to Amended and Restated Credit Agreement

Exhibit 10.34

Execution

FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

Dated as of November 1, 2006

among

ENERGY TRANSFER EQUITY, L.P.,

as the Borrower,

WACHOVIA BANK, NATIONAL ASSOCIATION,

as Administrative Agent,

UBS LOAN FINANCE LLC,

as Syndication Agent,

BNP PARIBAS, CITICORP NORTH AMERICA, INC., and

JPMORGAN CHASE BANK, N.A.

as Co-Documentation Agents,

and

The Other Lenders Party Hereto


		UBS SECURITIES LLC		AND		WACHOVIA CAPITAL MARKETS, LLC

Joint Lead Arrangers and Joint Book Managers

$1,300,000,000 Term Loans - Series B

FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

THIS FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (herein called the “First Amendment”) dated for reference as of November 1, 2006, by and between ENERGY TRANSFER EQUITY, L.P., a Delaware limited partnership (the “Borrower”), and WACHOVIA BANK, NATIONAL ASSOCIATION, as Administrative Agent, (in such capacity, the “Administrative Agent”), LC Issuer, and Swing Line Lender, and binding upon the financial institutions who are from time to time Lenders under the Credit Agreement as described herein, with the consent of the Majority Lenders under such Credit Agreement.

W I T N E S S E T H:

WHEREAS, the borrower has entered into that certain Amended and Restated Credit Agreement dated as of July 13, 2006 (herein, as from time to time amended, supplemented or restated, called the “Original Agreement”), by and among the borrower, Administrative Agent, the LC Issuer, Swingline Lender, Co-Syndication Agents, Co-Documentation Agents, Senior Managing Agents, and Managing Agents named therein and the Lenders from time to time party thereto, pursuant to which the LC Issuer, Swingline Lender and other Lenders (as defined therein) have agreed to advance funds and extend credit to the Borrower up to an aggregate principal amount of $650,000,000, subject to increases as provided therein up to an aggregate principal amount of $750,000,000; and

WHEREAS, the Borrower, the Administrative Agent, and the Majority Lenders desire to amend the Original Agreement as provided herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement and in consideration of the loans and other credit that may hereafter be extended by Lenders to the Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I. – Definitions and References

Section 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this First Amendment. The term the “Credit Agreement” shall mean the Original Agreement as amended by this First Amendment.

ARTICLE II. – Amendments to Original Agreement

Section 2.1. “Additional Definitions”. Article I of the Original Agreement is hereby amended to add the following definitions of “Commitment Increase Agreement”, “ETE Transactions”, “Term Loan Increase Conditions”, “Term Loan Increase” and “Unit Purchase Leverage Period”:

“‘Commitment Increase Agreement’ has the meaning given to such term in Section 2.18.”

“‘ETE Transactions’ means (i) the purchase by ETE for an aggregate cash consideration of not greater than $1,200,000,000 of Class G Units of ETP at a market price approved by a special committee of the Board of Managers of ETP LLC, (ii) the acquisition by the Borrower from ETI of the Class B limited partnership interests of ETP GP held by ETI (representing 50% of the total of such Class B limited partnership interests) in consideration for the issuance to ETI of additional limited partner interests of the Borrower plus the assumption of $70,500,000 of Indebtedness of ETI under that certain Credit and Guaranty Agreement dated April 24, 2006 among ETI, UBS AG, Stamford Branch, as administrative agent, and the lenders from time to time party thereto, (iii) the payment in full by the Borrower of all Indebtedness of ETI assumed as described in clause (ii) above and (iv) the release of all Liens in respect of the Class B Limited Partnership interests of ETP GP held by ETI acquired as described in clause (ii) above.”

“‘ETI’ means Energy Transfer Investments, L.P., a Delaware limited partnership.”

“‘Term Loan Increase’ has the meaning given to such term in Section 2.18.”

“‘Term Loan Increase Conditions’ mean each of the following: (i) subject only to the funding of the Term Loans to be made pursuant to Section 2.18(c), the consummation of the ETE Transactions, (ii) the terms of the Class G Units of ETP shall be substantially the same as the terms of the Class F Units of ETP, (iii) subject only to the funding of the Term Loans to be made pursuant to Section 2.18(c), the consummation by ETP of its acquisition of 50% of the ownership of CCE Holdings, LLC (“CCE”) pursuant to the Purchase and Sale Agreement dated as of September 14, 2006 by and among ETP, as the Buyer, and EFS-PA, LLC, CDPQ Investments (U.S.) Inc., Lake Bluff Inc., Merrill Lynch Ventures, L.P. 2001 and Kings Road Holdings I LLC, as the Sellers, and providing for the subsequent transfer to CCE of such 50% ownership of CCE in consideration for the transfer to ETP of 100% of the ownership of Transwestern Pipeline Company pursuant to the Redemption Agreement dated as of September 14, 2006 by and between ETP and CCE Holdings, LLC, involving, for all such transactions, an aggregate cash consideration of not greater than $1,500,000,000, (iv) the Borrower shall have on the date of the consummation of the ETE Transactions a senior secured debt rating by Moody’s and Fitch, (v) the Borrower and the Administrative Agent, on behalf of the Lenders shall have executed an appropriate Form U-1 pursuant to the Regulation U and X of the Board of Governors of the Federal Reserve System and the Administrative Agent has determined that, after giving effect to the Credit Extension in connection with the ETE Transactions, no violation of such Regulations shall have occurred, (vi) the Borrower shall have delivered to the Administrative Agent a duly completed pro forma Compliance Certificate as of August 31, 2006, signed by a Responsible Officer of the Borrower, reflecting, among other matters, compliance by the Borrower, on a pro forma basis after giving effect to the Credit Extension in connection with the ETE Transactions or otherwise, with the provisions of Section 7.12(a), (b) and (d) and such other assurances, certificates, documents, consents or opinions as the Administrative Agent reasonably may


		3		FIRST AMENDMENT TO CREDIT AGREEMENT

require, (vii) any fees required to be paid in connection with such Credit Extension shall have been paid, and (viii) the Borrower shall have paid all fees, charges and disbursements of counsel to the Administrative Agent to the extent invoiced prior to or on the consummation of the ETE Transactions.”

“‘Unit Purchase Leverage Period’ means the period from and including the date of the ETE Transactions to but not including the earlier of (i) May 30, 2007 or (ii) the date when the Borrower has received at least $300,000,000 of aggregate net cash proceeds of the issuance of its Equity Interests on or after the ETE Transactions.”

Section 2.2. Applicable Term Loan Rate. The definition of “Applicable Term Loan Rate” in Article I of the Original Agreement is amended to add the following to the end thereof:

“, except as otherwise provided pursuant to Section 2.18 in respect of Term Loans made in connection with a particular Term Loan Increase”

Section 2.3. Consolidated EBITDA of the Borrower. Paragraphs (a) and (b) of the definition of “Consolidated EBITDA of the Borrower” in Article I of the Original Agreement are amended in their entirety to read as follows:

“(a) the product of four (4) times the amount of cash distributions payable with respect to the last Fiscal Quarter in such period by ETP to the Borrower or its Restricted Subsidiaries in respect of limited partnership units in ETP to the extent actually received on or prior to the date the financial statements with respect to such Fiscal Quarter referred in the Section 6.02 are required to be delivered by the Borrower; provided that if the Borrower has acquired or disposed of any limited partnership units in ETP at any time after the first day of such Fiscal Quarter, the determinations in this clause (a) shall be made (other than for purposes of Section 7.12(c)) giving pro forma effect to such acquisition or disposition as if such acquisition or disposition had occurred on the first day of the Fiscal Quarter; plus

“(b) the product of four (4) times the amount of cash distributions payable with respect to the last Fiscal Quarter in such period by ETP to the Borrower or its Restricted Subsidiaries in respect of the general partnership interests or incentive distribution rights to the extent actually received on or prior to the date the financial statements with respect to such Fiscal Quarter referred in the Section 6.02 are required to be delivered by the Borrower; provided that any applicable determinations in this clause (b) after the acquisition by the Borrower from ETI of the Class B Interests in ETP GP LP shall be made (other than for purposes of Section 7.12(c)) giving pro forma effect to such acquisition (and the incentive distribution rights in ETP represented by such Class B Interests) as if such acquisition had occurred on the first day of the Fiscal Quarter; plus”

Section 2.4. Interest Period. Subclause (c) of the definition of “Interest Period” in Article I of the Original Agreement is hereby amended in its entirety to read as follows:


		4		FIRST AMENDMENT TO CREDIT AGREEMENT

“(c) no Interest Period shall extend beyond the Revolving Credit Maturity Date, in the case of Revolving Credit Loans, or the Term Loan Maturity Date applicable to such Loans, in the case of Term Loans.”

Section 2.5. Term Loan Maturity Date. The definition of “Term Loan Maturity Date” in Article I of the Original Agreement is amended to add the following to the end thereof:

“, or such other date as is otherwise provided pursuant to Section 2.18 in respect of the Terms Loans made in connection with a particular Term Loan Increase.”

Section 2.6. Value. The definition of “Value” in Article I of the Original Agreement is amended to insert the following sentence at the end of the definition:

“The ‘Value’ attributed to the Class G Units of ETP shall be the price of the common units of ETP, as provided above.”

Section 2.7. Term Loans. Section 2.01(b) of the Original Agreement is hereby amended to add the phrase “applicable to such Term Loans” after the words “Term Loan Maturity Date” in the second to last sentence of the section.

Section 2.8. Use of Proceeds. Section 2.05 of the Original Agreement is hereby amended to insert the following sentence immediately following the first sentence of such Section:

“The Borrower shall use the proceeds of the Term Loans made pursuant to Section 2.18(c): (a) to pay fees and expenses in connection with such Term Loans and the ETE Transactions, (b) to pay up to $1,200,000,000 of the cash required as payment of the purchase price of Class G Units of ETP and up to $70,500,000 of the cash required as payment of the Indebtedness assumed from ETI, each in connection with the ETE Transactions, and (c) with regard to the balance of the proceeds after using such proceeds in the manner described in clauses (a) and (b) of this sentence, to partially prepay the Revolving Credit Loans (but without reduction of the Revolving Credit Commitments).”

Section 2.9. Interest Rates. Section 2.12(a) of the Original Agreement is hereby amended by adding the following language at the end of clause (v):

“, with accrued unpaid interest being due and payable, whether on the Revolving Credit Loans or any of the Term Loans, on each Interest Payment Date and, on past due amounts, on demand.”

Section 2.10. Increase in Aggregate Revolving Credit Commitments. Section 2.17(a) of the Original Agreement is hereby amended to change the reference to “Section 2.18” in clause (ii) to “Section 2.18(b)”.

Section 2.11. Increase of Term Loans. Section 2.18 of the Original Agreement is hereby amended in its entirety to read as follows:


		5		FIRST AMENDMENT TO CREDIT AGREEMENT

“(a) The Borrower shall have the option, without the consent of the Lenders, to cause one or more increases in the Term Commitments pursuant to Section 2.18(b) or (c) (each a “Term Loan Increase”) by adding, subject to the prior approval of the Administrative Agent (such approval not to be unreasonably withheld), to this Agreement one or more financial institutions as Term Lenders (collectively, the “New Term Lenders”) or by allowing one or more Lenders to make a Term Commitment or increase their respective existing Term Commitments evidenced by a commitment increase agreement (each a “Commitment Increase Agreement”) meeting the requirements of Section 2.18(d).

“(b) The Borrower shall have the option from time to time to cause one or more Term Loan Increases by adding New Term Lenders or by allowing one or more Lenders to make a Term Commitment or increase their respective existing Term Commitments; provided however that: (i) prior to and after giving effect thereto, no Default or Event of Default shall have occurred hereunder and be continuing, (ii) no such increase shall cause the aggregate increases in Revolving Credit Commitments pursuant to Section 2.17 plus the aggregate Term Commitments obtained pursuant to this Section 2.18(b) to exceed $100,000,000, (iii) no Lender shall make a Term Commitment nor shall any Lender’s Term Commitment be increased without such Lender’s consent and (iv) no more than three requests may be made for increases in Revolving Credit Commitments pursuant to Section 2.17 or for increases in Term Commitments pursuant to this Section 2.18(b).

“(c) Contemporaneously with the ETE Transactions, the Borrower shall have the option to cause a single increase in the Term Commitments by adding New Term Lenders or by allowing one or more Lenders to make a Term Commitment or increase their respective existing Term Commitments; provided however that: (i) prior to and after giving effect thereto, no Default or Event of Default shall have occurred hereunder and be continuing, (ii) such increase in the aggregate Term Commitments obtained pursuant to this Section 2.18(c) shall not exceed $1,300,000,000, (iii) no Lender shall make a Term Commitment nor shall any Lender’s Term Commitment be increased without such Lender’s consent and (iv) each of the Term Loan Increase Conditions shall have been satisfied. The Term Loan Maturity Date for the Terms Loans made pursuant to the Term Loan Increase pursuant to this Section 2.18(c) shall be specified in applicable Commitment Increase Agreement, and shall not be earlier than the existing Term Loan Maturity Date. Such Term Loan Maturity Date for such Term Loan Increase shall not change in any manner the Term Loan Maturity Date for the other Term Loans.

“(d) Each Commitment Increase Agreement required pursuant to Section 2.18(b) or (c) shall (i) be in form and substance acceptable to the Administrative Agent, (ii) be executed by the Borrower, the Administrative Agent, New Term Lenders, if any, making an initial Term Commitment and Lenders, if any, increasing their existing Term Commitments, and (iii) indicate the amount and allocation of such Term Commitments and the effective date


		6		FIRST AMENDMENT TO CREDIT AGREEMENT

thereof (the applicable “Term Commitment Effective Date”). The Commitment Increase Agreement required in connection with a Term Loan Increase pursuant to Section 2.18(c) shall also indicate the Term Loan Maturity Date applicable to the Terms Loans made in connection with such Term Loan Increase. Each of the Applicable Term Loan Rates in respect of the Term Loans made in connection with any Term Loan Increase may be increased by the applicable Commitment Increase Agreement or by an amendment to this Agreement or by a separate agreement entered into between the Borrower and the Administrative Agent, with the consent of the Lenders making the Term Loans in connection with such Term Loan Increase, but without the consent of any other Lender. Each Term Loan made pursuant to a Term Loan Increase that has a Term Loan Maturity Date or Applicable Term Loan Rate that is different than those of the Term Loans originally made pursuant to Section 2.01 shall be designed as a separate Series (“Series B,” “Series C”, etc) in the applicable Commitment Increase Agreement, and each assignment or participation of any such Term Loan shall identify such Terms Loan by such Series designation and disclose the Term Loan Maturity Date or Applicable Term Loan Rate, as applicable, for such Term Loan. Each financial institution that becomes a New Term Lender pursuant to this Section 2.18 by the execution and delivery to the Administrative Agent of the applicable Commitment Increase Agreement shall be a “Term Lender” and a “Lender” for all purposes under this Agreement on the applicable Term Commitment Effective Date and shall make its Term Loan on such Term Commitment Effective Date. The Borrower shall continue or convert Term Loans on each Term Commitment Effective Date (and pay any additional amounts required pursuant to Section 3.06) to the extent necessary to keep the outstanding Term Loans of each Lender of the same Type ratable with existing Term Loans of the same Type.

“(e) As a condition precedent to each Term Commitment pursuant to Section 2.18(b) or (c) above, the Borrower shall deliver to the Administrative Agent, to the extent requested by the Administrative Agent, the following in form and substance satisfactory to the Administrative Agent:

(i) a certificate dated as of the applicable Term Commitment Effective Date, signed by a Responsible Officer of the Borrower certifying that each of the conditions to such increase set forth in this Section shall have occurred and been complied with and that, before and after giving effect to such increase, (A) the representations and warranties contained in this Agreement and the other Loan Documents are true and correct in all material respects on and as of the Term Commitment Effective Date after giving effect to such increase, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they were true and correct in all material respects as of such earlier date, and (B) no Default or Event of Default exists;

(ii) such certificates of resolutions or other action, incumbency certificates and/or other certificates of Responsible Officers of the Borrower and each Guarantor as the Administrative Agent may require


		7		FIRST AMENDMENT TO CREDIT AGREEMENT

evidencing the identity, authority and capacity of each Responsible Officer thereof authorized to act as a Responsible Officer in connection with such Commitment Increase Agreement and any Guarantors’ Consent to such Commitment Increase Agreement, and such documents and certifications as the Administrative Agent may require to evidence that the Borrower and each Guarantor is validly existing and in good standing in its jurisdiction of organization; and

(iii) a favorable opinion of independent legal counsel reasonably acceptable to the Administrative Agent, in form and substance reasonably satisfactory to the Administrative Agent, relating to such Commitment Increase Agreement, the any Guarantors’ Consent to such Commitment Increase Agreement, and any related or contemporaneous transactions, addressed to the Administrative Agent and each Lender.”

Section 2.12. Limitation on Restricted Payments. Clauses (c) of Section 7.05 of the Original Agreement are hereby amended to delete the phrase “up to a maximum purchase price in the aggregate during the term of this Agreement of $20,000,000”.

Section 2.13. Leverage Ratio of the Borrower. Subclauses (A) and (B) of clause (iii) of Section 7.12(a) of the Original Agreement are hereby amended to read as follows:

“(A) 4.50 to 1.00 at any time other than during a Specified Acquisition Period or the Unit Purchase Leverage Period, (B) 5.00 to 1.00 during a Specified Acquisition Period, and (C) 5.25 to 1.00 during the Unit Purchase Leverage Period.”

Section 2.14. Interest Coverage Ratio. Section 7.12(c) of the Original Agreement is hereby amended to read as follows:

“(c) Interest Coverage Ratio. The ratio of (i) Consolidated EBITDA of the Borrower for each period of four consecutive Fiscal Quarters to (ii) Consolidated Interest Expense for such period will never be less than (A) 3.00 to 1.0 at any time other than during the Unit Purchase Leverage Period and (B) 2.50 to 1.00 during the Unit Purchase Leverage Period.

ARTICLE III. – Conditions of Effectiveness

Section 3.1. Effective Date. This First Amendment shall become effective November 1, 2006 (the “Effective Date”), and is expressly conditioned, upon the receipt by the Administrative Agent, at the Administrative Agent’s office, of a counterpart of this First Amendment executed and delivered by the Borrower and the Administrative Agent, a counterpart of the Guarantors’ Consent and Agreement attached hereto signed by each of the Guarantors, and a counterpart of the Lenders’ Consent attached hereto signed by Lenders constituting Majority Lenders.


		8		FIRST AMENDMENT TO CREDIT AGREEMENT

ARTICLE IV. – Representations and Warranties

Section 4.1. Representations and Warranties. In order to induce the Administrative Agent and the Lenders to execute and deliver this First Amendment, the Borrower represents and warrants to each Lender that:

(a) The representations and warranties contained in Article V of the Original Agreement are true and correct in all material respects at and as of the time of the effectiveness hereof, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct as of such earlier date.

(b) The Borrower has duly taken all action necessary to authorize the execution and delivery by it of this First Amendment, the Borrower is duly authorized to borrow monies under the Credit Agreement, and the Borrower is duly authorized to perform its obligations under the Credit Agreement.

(c) The execution and delivery by the Borrower of this First Amendment, the performance by the Borrower of its obligations hereunder and the consummation of the transactions contemplated hereby do not and will not conflict with any Law or of the organizational documents of any Restricted Person, or of any material agreement, judgment, license, order or permit applicable to or binding upon any Restricted Person, or result in the creation of any Lien upon any assets or properties of any Restricted Person. Except for those which have been obtained, no consent, approval, authorization or order of any Tribunal or third party is required in connection with the execution and delivery by the Borrower of this First Amendment or the consummation by any Restricted Person of the transactions contemplated hereby.

(d) When duly executed and delivered, this First Amendment will be a legal and binding obligation of the Borrower enforceable in accordance with its terms, except as limited by bankruptcy, insolvency or similar laws of general application relating to the enforcement of creditors’ rights and by equitable principles of general application.

ARTICLE V. – Miscellaneous

Section 5.1. Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The execution, delivery and effectiveness of this First Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders or the Administrative Agent under the Credit Agreement, the Notes, or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement, the Notes or any other Loan Document.

Section 5.2. Survival of Agreements. All representations, warranties, covenants and agreements of the Borrower herein shall survive the execution and delivery of this First Amendment and the performance hereof, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered


		9		FIRST AMENDMENT TO CREDIT AGREEMENT

by any Restricted Person hereunder or under the Credit Agreement to the Administrative Agent or any Lender shall be deemed to constitute representations and warranties by, and agreements and covenants of, the Borrower under this First Amendment and under the Credit Agreement.

Section 5.3. Loan Documents. This First Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto.

Section 5.4. Governing Law. This First Amendment shall be governed by and construed in accordance with the laws applicable to the Credit Agreement.

Section 5.5. Counterparts. This First Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same First Amendment.

THIS FIRST AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

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		10		FIRST AMENDMENT TO CREDIT AGREEMENT

IN WITNESS WHEREOF, this Amendment is executed as of the date first written above.


BORROWER:	ENERGY TRANSFER EQUITY, L.P.

	By:	LE GP, LLC, its general partner

	By:	/s/ John W. McReynolds
		John W. McReynolds
		President and Chief Financial Officer

	WACHOVIA BANK, NATIONAL ASSOCIATION, as the Administrative Agent, LC Issuer and Swing Line Lender

	By:	/s/ Todd Schanzlin
	Name:	Todd Schanzlin
	Title:	Vice President

FIRST AMENDMENT TO CREDIT AGREEMENT

Lenders’ Consent to First Amendment

to Credit Agreement

IN WITNESS WHEREOF, the undersigned Lender hereby consents to the First Amendment to Amended and Restated Credit Agreement dated for reference as of November 1, 2006, among ENERGY TRANFER EQUITY, L.P., and WACHOVIA BANK, NATIONAL ASSOCIATION, as the Administrative Agent, LC Issuer and Swing Lender.



Name of Lender

By:
Name:
Title:

CONSENT AND AGREEMENT

November 1, 2006

Reference is hereby made to (i) that certain First Amendment to Amended and Restated Credit Agreement dated for reference of even date herewith (the “First Amendment”) by and among Energy Transfer Equity, L.P., a Delaware limited partnership (the “Borrower”), Wachovia Bank, National Association, as administrative agent (the “Administrative Agent”), LC Issuer and Swing Line Lender and the Lenders party thereto (“Lenders”), (ii) that certain Amended and Restated Credit Agreement dated as of July 13, 2006 (as amended, supplemented, modified or restated, the “Credit Agreement”) by and among the Borrower, the Administrative Agent and Lenders, and (iii) the Pledge and Security Agreement (as supplemented, modified or restated, the “Pledge Agreement”) to which each of the undersigned is a party. Terms that are defined in the Credit Agreement and used but not defined herein have the meanings given to them in the Credit Agreement.

By its execution below, each of the undersigned hereby (a) consents to the provisions of the First Amendment and the transactions contemplated therein, (b) ratifies and confirms the Pledge Agreement, (c) ratifies, confirms and agrees that all obligations arising under the Credit Agreement shall be secured under and pursuant to the Pledge Agreement, (d) agrees that all of its respective obligations and covenants under the Pledge Agreement shall remain unimpaired by the execution and delivery of the First Amendment and the other documents and instruments executed in connection therewith, and (e) agrees that the Pledge Agreement shall remain in full force and effect.

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IN WITNESS WHEREOF, this Consent and Agreement is executed as of the date first above written.


ENERGY TRANSFER EQUITY, L.P.

	By:	LE GP, LLC, its general partner

	By:	/s/ John W. McReynolds
		John W. McReynolds
		President and Chief Financial Officer

ENERGY TRANSFER PARTNERS, L.L.C.

	By:	Energy Transfer Equity, L.P, its sole member

		By:	LE GP, LLC, its general partner

		By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer

Consent And Agreement To First Amendment To Credit Agreement

Contribution and Conveyance Agreement

Exhibit 10.35

CONTRIBUTION AND CONVEYANCE AGREEMENT

by and among

ENERGY TRANSFER PARTNERS, L.P.

AND

ENERGY TRANSFER EQUITY, L.P.

(Class G Units)

Dated November 1, 2006

CONTRIBUTION AND CONVEYANCE AGREEMENT

THIS CONTRIBUTION AND CONVEYANCE AGREEMENT, dated November 1, 2006 (this “Agreement”), is made by Energy Transfer Partners, L.P., a limited partnership formed under the laws of the State of Delaware ( “ETP” or the “Partnership”), on the one hand, and Energy Transfer Equity, L.P., a limited partnership formed under the laws of the State of Delaware ( “ETE”), on the other hand.

WHEREAS, ETP desires to issue to ETE, in exchange for a contribution by ETE of cash, limited partner interests of the Partnership, consisting of Class G Units (the “Class G Units”), having the characteristics set forth in Amendment No. 10 to the Amended and Restated Agreement of Limited Partnership of the Partnership (“Amendment No. 10”), a copy of which is attached hereto as Exhibit A.

NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth herein and for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, ETP and ETE hereby agree as follows:

ARTICLE I.

DEFINITIONS

Section 1.01 Definitions. As used in this Agreement, and unless the context requires a different meaning, the following terms have the meanings indicated:

“Cash Contribution” shall have the meaning specified in Section 2.01.

“CCE Purchase Agreement” means the Purchase and Sale Agreement, dated as of September 14, 2006, among the Partnership and the Class B Members of CCE Holdings, LLC.

“Class G Units” shall have the meaning specified in Section 2.02.

“Closing” shall have the meaning specified in Section 2.03.

“Closing Date” shall have the meaning specified in Section 2.03.

“Common Units” means common units representing limited partnership interests of ETP.

“Commission” means the United States Securities and Exchange Commission.

“ETP” has the meaning set forth in the introductory paragraph.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Governmental Authority” means, with respect to a particular Person, the country, state, county, city and political subdivisions in which such Person, such Person’s Subsidiaries or such Person’s Property is located or which exercises valid jurisdiction over any such Person or such Person’s Property, and any court, agency, department, commission, board, bureau or

instrumentality of any of them and any monetary authority which exercises valid jurisdiction over any such Person or such Person’s Property.

“Material Adverse Effect” means any event or condition that has had or could reasonably be expected to (i) have a material adverse effect on the financial condition, results of operations, business or prospects of such party, (ii) result in termination of the CCE Purchase Agreement, (iii) result in a breach or violation of any representation, warranty, covenant or condition contained in the CCE Purchase Agreement as a result of which a party to the CCE Purchase Agreement has, or with notice, the lapse of time or both, is likely to have, the right to terminate the CCE Purchase Agreement or (iv) impair or affect adversely such party’s ability to perform its obligations under the Agreement or impair or delay completion of the transactions contemplated hereby or by the CCE Purchase Agreement.

“Person” means any individual, corporation, company, voluntary association, partnership, joint venture, trust, limited liability company, unincorporated organization or government or any agency, instrumentality or political subdivision thereof, or any other form of entity.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible.

“Securities Act” means the Securities Act of 1933, as amended.

“Subsidiary” means, as to any Person, any corporation or other entity of which: (i) such Person or a Subsidiary of such Person is a general partner or manager; or (ii) at least a majority of the outstanding equity interest having by the terms thereof ordinary voting power to elect a majority of the board of directors or similar governing body of such corporation or other entity (irrespective of whether or not at the time any equity interest of any other class or classes of such corporation or other entity shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by such Person or one or more of its Subsidiaries.

“Transwestern” means Transwestern Pipeline Company, LLC, a Delaware limited liability company.

ARTICLE II.

CONTRIBUTIONS, ACKNOWLEDGMENTS AND DISTRIBUTIONS

Section 2.01 Contribution of Cash to ETP. Subject to the terms and conditions hereof, ETE hereby agrees to contribute, grant, bargain, convey, assign, transfer, set over and deliver to ETP, its successors and assigns, cash in the amount of $1.2 billion (“Cash Contribution”) as a contribution to the capital of ETP and ETP hereby agrees to accept such Cash Contribution as a contribution to the capital of ETP.

Section 2.02 Issuance of Class G Units. Subject to the terms and conditions of this Agreement, ETP agrees to issue to ETE, 26,086,957 Class G Units the “Class G Units”) in exchange for the contribution of the Cash Contribution by ETE and ETE hereby agrees to accept the Class G Units in exchange for its capital contribution of the Cash Contribution to ETP. The issuance of the Class G Units contemplated hereby will not be registered with the Securities and

Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”) and the certificates representing such Class G Units shall be issued bearing a restrictive legend thereon in the form of Exhibit B attached hereto.

Section 2.03 Closing and Delivery of Class G Units.

(a) Subject to the terms and conditions hereof, the closing of the transactions constituting the issuance of the Class G Units and the contribution of the Cash Contribution (the “Closing”) shall take place at the offices of Vinson & Elkins, L.L.P., counsel to ETE, 1001 Fannin Street, Houston, Texas, at 3:00 p.m. Central Time on November 1, 2006, or such other date, place and time as ETP and ETE may agree (the “Closing Date”).

(b) The Class G Units to be issued to ETE under this Agreement shall be delivered by or on behalf of ETP to ETE at the Closing in certificated form.

(c) The Cash Contribution shall be by payment by wire transfer in immediately available funds to such bank account of ETP designated by ETP in writing no later than the Business Day immediately preceding the Closing Date. “Business Day” means any day other than (a) a Saturday, Sunday or legal holiday in New York City, or (b) a day on which the commercial banks in New York City are authorized or required by law or executive order to close.

Section 2.04 Conditions to the Closing.

(a) ETE’s Conditions. The obligations of ETE to consummate the purchase of its Class G Units shall be subject to the satisfaction on or prior to the Closing Date of the following conditions (any or all of which may be waived by ETE in writing, in whole or in part, to the extent permitted by applicable Law):

(i) the representations and warranties of ETP contained in this Agreement shall be true and correct in all material respects both when made and at and as of the Closing Date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such date), and ETE shall have received an officer’s certificate signed on behalf of ETP to such effect;

(ii) the execution and delivery by ETP of a Registration Rights Agreement in the form attached hereto as Exhibit C; and

(iii) all conditions to closing under the CCE Purchase Agreement have been satisfied or waived other than the delivery of closing items pursuant to Section 2.4 of the CCE Purchase Agreement;

(b) ETP’s Conditions. The obligation of ETP to consummate the issuance of the Class G Units to ETE shall be subject to the satisfaction on or prior to the Closing Date of the following conditions (which may be waived by ETP in writing, in whole or in part, to the extent permitted by applicable Law):

(i) the representations and warranties of ETE contained in this Agreement shall be true and correct in all material respects both when made and at and as of the Closing Date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such date), and ETP shall have received an officer’s certificate from ETE signed on behalf of ETE to such effect;

(ii) all conditions to closing under the CCE Purchase Agreement have been satisfied or waived other than the delivery of closing items pursuant to Section 2.4 of the CCE Purchase Agreement;

(iii) payment to ETP of the amount of the Cash Contribution in exchange for the Class G Units; and

(iv) the execution and delivery by ETE of the Registration Rights Agreement.

ARTICLE III.

REPRESENTATIONS AND WARRANTIES OF ETP

ETP represents and warrants to ETE as follows:

Section 3.01 Existence. ETP (i) is a limited partnership duly organized, legally existing and in good standing under the laws of the State of Delaware and (ii) has all requisite power and authority, and has all governmental licenses, authorizations, consents and approvals necessary, to own, lease, use and operate its Properties and carry on its business as its business is now being conducted, except where the failure to obtain such licenses, authorizations, consents and approvals would not be reasonably likely to have a Material Adverse Effect.

Section 3.02 Valid Issuance of Class G Units. ETP has taken all necessary action to approve and adopt Amendment No. 10 as an amendment to the Amended and Restated Agreement of Limited Partnership of ETP, as amended as of the date of this Agreement (the “Partnership Agreement”) and no approval of the limited partners of ETP is necessary for the approval and adoption of Amendment No. 10. Amendment No. 10 has been duly executed, delivered and adopted by ETP as an amendment to the Partnership Agreement. ETE, when such Class G Units are delivered as provided in this Agreement, will be entitled to the rights of a unitholder of limited partner interests of ETP as conferred by the Partnership Agreement, as amended by Amendment No. 10, and applicable law. The issuance of the Class G Units and the limited partner interests represented thereby have been duly authorized by ETP and, when issued and delivered to ETE against payment therefor in accordance with the terms of this Agreement, will be validly issued, fully paid (to the extent required under the Partnership Agreement) and nonassessable (except as such nonassessability may be affected by such matters described under the caption “The Partnership Agreement—Limited Liability” in ETP’s Registration Statement on Form S-3 (File No. 333-133174).

Section 3.03 Authority. ETP has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; and the execution, delivery and performance by ETP of this Agreement has been duly authorized by all necessary action on its part; and this Agreement constitutes the legal, valid and binding obligations of ETP, enforceable in accordance

with its terms, except as such enforceability may be limited by bankruptcy, insolvency, fraudulent transfer and similar laws affecting creditors’ rights generally or by general principles of equity. No approval from the equity owners of ETP is required in connection with the transactions contemplated by this Agreement.

Section 3.04 Approvals. No authorization, consent, approval, waiver, license, qualification or written exemption from, nor any filing, declaration, qualification or registration with, any Governmental Authority or any other Person (each, a “Consent”) is required for the issuance and delivery of the Class G Units being sold by ETP to ETE or in connection with the execution, delivery or performance by ETP of this Agreement other than Consents that have been obtained.

Section 3.05 No Breach. The execution and delivery of this Agreement, the compliance by ETP with all the provisions of, and the performance by ETP of its obligations under, this Agreement, and the consummation of the transactions contemplated in this Agreement will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, (i) the constitutive documents of ETP, (ii) any instrument, contract or other agreement to which ETP is a party or by which ETP is bound or to which any of its Properties or assets may be bound or subject, in each case, the breach or violation of which or default under which would be reasonably expected to have a Material Adverse Effect on the ability of ETP to comply with its obligations hereunder, or (iii) any law or statute or any order, rule or regulation of any Governmental Authority.

Section 3.06 Title. Such Class G Units are not subject to any conflicting sale, transfer, assignment, or any agreement (other than this Agreement) to assign, convey, or transfer, in whole or in part, any of such Class G Units, and upon consummation of such Purchase, ETE will receive good and marketable title to such Class G Units, free and clear of any encumbrance, liens, claims, charges, security interests, or other interests of others, except to the extent of any encumbrance, lien, claim, charge, security interest or other interest created by ETE.

Section 3.07 Legal Proceedings. There are no legal or governmental proceedings pending to which ETP is a party or of which any property of ETP is the subject that, if determined adversely to ETP, would individually or in the aggregate have a Material Adverse Effect on ETP, and, to the best of ETP’s knowledge, no such proceedings are threatened or contemplated by any such Governmental Authority or threatened by others.

Section 3.08 ETP Commission Documents. ETP has filed with the Commission all forms, registration statements, reports, schedules and statements required to be filed by it under the Exchange Act or the Securities Act within the 18 months prior to the date of this Agreement (all such documents, collectively “ETP Commission Documents”). ETP Commission Documents, including, without limitation, any audited or unaudited financial statements and any notes thereto or schedules included therein, at the time filed (in the case of registration statements, solely on the dates of effectiveness) (except to the extent corrected by a subsequently filed ETP Commission Document filed prior to the date hereof) (a) complied as to form in all material respects with applicable accounting requirements and with the published rules and regulations of the Commission with respect thereto, (b) were prepared in accordance with generally accepted accounting principles applied on a consistent basis during the periods

involved (except as may be indicated in the notes thereto or, in the case of unaudited statements, as permitted by the applicable rules and regulations of the Commission), and (c) fairly present (subject in the case of unaudited statements to normal, recurring and year-end audit adjustments) in all material respects the consolidated financial position and status of the business of ETP as of the dates thereof and the consolidated results of its operations and cash flows for the periods then ended.

Section 3.09 No Material Adverse Changes. Except as disclosed in the documents filed by ETP under the Exchange Act, since the date of ETP’s most recent Form 8-K (to the extent it contains financial results and balance sheet information) or Form 10-Q filing with the Commission, ETP and its subsidiaries have conducted their respective businesses in the ordinary course, consistent with past practice, and there has been no change, event, occurrence, fact, circumstance or condition that has had or would be reasonably likely to have a Material Adverse Effect on the assets, liabilities, financial condition, business, operations or affairs of ETP and its subsidiaries, taken as a whole.

Section 3.10 CCE Purchase Agreement. The CCE Purchase Agreement is in full force and effect and, to the best knowledge of ETP, no event or circumstance has occurred or exists as a result of which (i) the closing under the CCE Purchase Agreement will be delayed or (ii) any party to the CCE Purchase Agreement has, or with notice or the lapse of time or both is likely to have the right to terminate the CCE Purchase Agreement.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES OF ETE

ETE represents and warrants to ETP as follows:

Section 4.01 Existence. ETE (i) is an entity duly organized, legally existing and in good standing under the laws of its jurisdiction of organization and (ii) has all requisite power and authority, and has all governmental licenses, authorizations, consents and approvals necessary, to own, lease, use and operate its Properties and carry on its business as its business is now being conducted, except where the failure to obtain such licenses, authorizations, consents and approvals would not be reasonably likely to have a Material Adverse Effect.

Section 4.02 Authority. ETE has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; and the execution, delivery and performance by ETE of this Agreement have been duly authorized by all necessary action on its part; and this Agreement constitutes a legal, valid and binding obligations of ETE, enforceable in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency, fraudulent transfer and similar laws affecting creditors’ rights generally or by general principles of equity. No approval from the equity owners of ETE is required in connection with the transactions contemplated by this Agreement.

Section 4.03 Approvals. No authorization, consent, approval, waiver, license, qualification or written exemption from, nor any filing, declaration, qualification or registration with, any Governmental Authority or any other Person is required in connection with the execution, delivery or performance by ETE of this Agreement.

Section 4.04 No Breach. The execution and delivery of this Agreement by ETE, the compliance by ETE with all of the provisions of, and the performance by ETE of its obligations under this Agreement and the consummation of the transactions contemplated in this Agreement will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, (A) the constitutive documents of ETE, (B) any instrument, contract or other agreement to which ETE is a party or by which ETE is bound or to which any of its Properties or assets may be bound or subject, in each case, the breach or violation of which or default under which would be reasonably expected to have a Material Adverse Effect on the ability of ETE to comply with its obligations hereunder, or (C) any law or statute or any order, rule or regulation of any Governmental Authority and no consent, approval, authorization, order, registration, clearance or qualification or notification of, with or to any such Governmental Authority is required of ETE for the purchase of the Class G Units by ETE contemplated by this Agreement.

Section 4.05 Legal Proceedings. There are no legal or governmental proceedings pending to which ETE is a party or of which any property of ETE is the subject that, if determined adversely to ETE, would individually or in the aggregate have a Material Adverse Effect on ETE’s ability to perform its obligations under this Agreement, and, to the best of ETE’s knowledge, no such proceedings are threatened or contemplated by any such Governmental Authority or threatened by others.

Section 4.06 Nature of the Investor. ETE (a) is an “accredited investor” as defined in Rule 501(a) of Regulation D promulgated under the Act, (b) is able to bear the economic risk of losing its entire investment in the Class G Units, and (c) has knowledge and experience in financial and business matters such that it is capable of evaluating the risks and merits of this investment.

Section 4.07 Investment. ETE is acquiring the Class G Units for its own account, and not with a view to any distribution, resale, subdivision, or fractionalization thereof in violation of the Securities Act or any other applicable domestic securities law, and ETE has no present plans to enter into any contract, undertaking, agreement or arrangement for any such distribution, resale, subdivision, or fractionalization of the Class G Units. ETE acknowledges and agrees that, based in part upon its representations contained herein and in reliance upon applicable exemptions, the issuance of the Class G Units has not been registered under the Act or the securities laws of any other domestic or foreign jurisdiction and that accordingly, the Class G Units may not be offered for sale, sold, or otherwise transferred in whole or in part, except in accordance with the terms of the Partnership Agreement and in compliance with all applicable laws, including securities laws, except that the Class G Units may be pledged in a bona fide transaction.

Section 4.08 Receipt of Information. ETE has carefully reviewed the documents filed by ETP with the Commission under the Exchange Act within the 18 months prior to the date of this Agreement, including ETP’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, current reports on Form 8-K and other filings (the “Partnership Information”) and acknowledges that ETP has provided to ETE or its representatives all agreements, documents, records and books that ETE or its representatives have requested relating to an investment in ETP.

ARTICLE V.

COVENANTS

Section 5.01 Other Agreements.

(a) ETP hereby agrees to prepare and cause to be filed with the Commission a proxy statement providing for the submission for approval of ETP’s common unitholders a proposal to convert the Class G Units to Common Units on a one-for-one basis as specified in Amendment No. 10 (the “Proxy Statement”).

(b) Each party agrees that it will indemnify and hold harmless the other party from and against any and all claims, demands, or liabilities for broker’s, finder’s, placement, or other similar fees or commissions incurred by such party or alleged to have been incurred by such party in connection with the purchase of the Class G Units or the consummation of the transactions contemplated by this Agreement.

Section 5.02 Information. ETE shall supply such information with respect to itself, its directors, officers and shareholders as ETP may reasonably request for the purpose of preparation of the Proxy Statement. ETP shall supply to ETE such information with respect to itself, its directors, officers and unitholders, Transwestern and such other matters as ETE may reasonably request for the purpose of preparation of any notice, form or other documents required to be filed with any Governmental Authority in connection with the transaction contemplated by this Agreement.

Section 5.03 Further Assurances. Each party agrees to execute, acknowledge and deliver such further instruments and to do all such other acts as may be necessary or appropriate to carry out the purposes and intent of this Agreement.

ARTICLE VI.

MISCELLANEOUS

Section 6.01 Interpretation and Survival of Provisions. Article, Section and Exhibit references are to this Agreement, unless otherwise specified. All references to instruments, documents, contracts, and agreements are references to such instruments, documents, contracts, and agreements as the same may be amended, supplemented, and otherwise modified from time to time, unless otherwise specified.

Section 6.02 No Waiver; Modifications in Writing.

(a) Delay. No failure or delay on the part of any party in exercising any right, power, or remedy hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right, power, or remedy preclude any other or further exercise thereof or the exercise of any right, power, or remedy. The remedies provided for herein are cumulative and are not exclusive of any remedies that may be available to a party at law or in equity or otherwise.

(b) Specific Waiver. Except as otherwise provided herein, no amendment, waiver, consent, modification, or termination of any provision of this Agreement shall be effective unless signed by each of the parties hereto or thereto affected by such amendment,

waiver, consent, modification, or termination. Any amendment, supplement or modification of or to any provision of this Agreement, any waiver of any provision of this Agreement, and any consent to any departure by any party hereto from the terms of any provision of this Agreement shall be effective only in the specific instance and for the specific purpose for which made or given.

Section 6.03 Binding Effect; Assignment.

(a) Binding Effect. This Agreement shall be binding upon ETP, ETE, and their respective successors and permitted assigns. Except as expressly provided in this Agreement, this Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement, and their respective successors and permitted assigns.

(b) Assignment of Class G Units. All or any portion of ETE’s Class G Units purchased pursuant to this Agreement may be sold, assigned or pledged by ETE, subject to compliance with applicable securities laws.

Section 6.04 Assignment of Rights. All or any portion of the rights and obligations of ETE under this Agreement may not be transferred by ETE without the written consent of ETP.

Section 6.05 Costs and Expenses. Each party hereto shall be responsible for the payment of the costs and expenses incurred by it in connection with the negotiation, execution, delivery and performance of this Agreement and the transactions contemplated hereby.

Section 6.06 Notices. All notices and demands provided for hereunder shall be in writing and shall be given by registered or certified mail, return receipt requested, telecopy, air courier guaranteeing overnight delivery or personal delivery to the following addresses:

(a)

to ETP, at:

Energy Transfer Partners, L.P.

8801 South Yale Avenue, Suite 310

Tulsa, Oklahoma 74137

Facsimile: 918/493-7290

Attention: H. Michael Krimbill

(b)

to ETE, at:

Energy Transfer Equity, L.P.

2828 Woodside Street

Dallas, Texas 75204

Facsimile: 214/981-0701

Attention: John W. McReynolds

or to such other address as ETP or ETE may designate in writing. All notices and communications shall be deemed to have been duly given: at the time delivered by hand, if personally delivered; upon actual receipt if sent by certified mail, return receipt requested, or

regular mail, if mailed; when receipt acknowledged, if sent via facsimile; and upon actual receipt when delivered to an air courier guaranteeing overnight delivery.

Section 6.07 Governing Law. This Agreement will be construed in accordance with and governed by the laws of the State of Delaware without regard to any otherwise applicable principles of conflicts of laws.

Section 6.08 Entire Agreement. This Agreement and the other documents referred to herein are intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein and therein. This Agreement and the other documents referred to herein supersede all prior agreements and understandings between the parties with respect to such subject matter.

Section 6.09 Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same Agreement.

Section 6.10 Equitable Relief. Each party hereto agrees that money damages would not be a sufficient remedy for any breach of this Agreement by either party hereto or their respective Representatives and that the non-breaching party shall be entitled to equitable relief, including injunction and specific performance, in the event of any such breach, in addition to all other remedies available to the non-breaching party at law or in equity. Each party further agrees to waive any requirement for the securing or posting of any bond in connection with such remedy.

[Signature page follows]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed, as of the date and year first above written.


ENERGY TRANSFER PARTNERS, L.P.

By:		Energy Transfer Partners GP, L.P.,
		Its general partner
By:		Energy Transfer Partners, L.L.C.,
		Its general partner

By:		/s/ H. Michael Krimbill
Name:		H. Michael Krimbill
Title:		President

ENERGY TRANSFER EQUITY, L.P.

By:		LE GP, LLC,
		Its general partner

By:		/s/ John W. McReynolds
Name:		John W. McReynolds
Title:		President

SIGNATURE PAGE TO

CONTRIBUTION AND CONVEYANCE AGREEMENT

EXHIBIT A

AMENDMENT NO. 10 TO PARTNERSHIP AGREEMENT

EXHIBIT A

EXHIBIT B

CERTIFICATE LEGEND

EXHIBIT B

EXHIBIT C

REGISTRATION RIGHTS AGREEMENT

EXHIBIT C

Contribution, Assumption and Conveyance Agreement

Exhibit 10.36

CONTRIBUTION, ASSUMPTION AND CONVEYANCE AGREEMENT

THIS CONTRIBUTION, ASSUMPTION AND CONVEYANCE AGREEMENT, dated as of November 1, 2006, is entered into by and between ENERGY TRANSFER EQUITY, L.P., a Delaware limited partnership (“ETE”) and ENERGY TRANSFER INVESTMENTS, L.P., a Delaware limited partnership (“ETI”). The parties to this agreement are collectively referred to herein as the “Parties.” Capitalized terms used herein shall have the meanings assigned to such terms in Section 1.1.

RECITALS

WHEREAS, ETI owns a 50% Class B limited partner interest (the “IDR Interest”) in Energy Transfer Partners GP, L.P. (“ETP GP”);

WHEREAS, ETI is a party that certain Credit and Guaranty Agreement, dated as of April 24, 2006, as amended by that certain Amendment Number 1 to Credit and Guaranty Agreement, dated as of July 21, 2006, naming ETI, UBS AG, Stamford Branch, as Administrative Agent and Collateral Agent, UBS Securities LLC as Arranger and the lenders from time to time party thereto (the “Lenders”) (the “Loan Agreement”);

WHEREAS, ETI proposes to assign and transfer all of its rights and obligations under the Loan Agreement to ETE;

WHEREAS, ETI desires to assign all of its rights and obligations under the Loan Agreement and ETE desires to accept such assignment and assume such obligations;

WHEREAS, ETI desires to contribute the IDR Interest to ETE in exchange for 83,148,900 Class C common units in ETE (the “Class C Units”), the assumption of the Loan Agreement by ETE, and ETE desires to issue the Class C units and accept the assignment of, and assume the obligations of ETI, the Loan Agreement in exchange for the IDR Interest; and

WHEREAS, the Class C Units will have the characteristics set forth in Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of ETE, a copy of which is attached hereto as Exhibit A (“Amendment No. 1”).

NOW, THEREFORE, in consideration of the premises, warranties, covenants and agreements contained herein, the parties agree as follows:

ARTICLE 1

DEFINITIONS

Section 1.1 The following capitalized terms shall have the meanings given below.

(a) “Agreement” means this Contribution and Conveyance Agreement.

(b) “Common Unit” has the meaning assigned to such term in the ETE Partnership Agreement.

(d) “Closing Date” has the meaning specified in Section 3.1.

(e) “ETE Partnership Agreement” means the Third Amended and Restated Agreement of Limited Partnership of ETE dated as of February 8, 2006, as amended by Amendment No. 1, dated as of the Closing Date.

(f) “ETP” means Energy Transfer Partners, L.P., a Delaware limited partnership.

(g) “ETP GP Partnership Agreement” means the Amended and Restated Agreement of Limited Partnership of ETP GP, dated as of February 8, 2006.

(h) “ETP GP LLC Agreement” means the Amended and Restated Limited Liability Company Agreement Energy Transfer Partners, L.L.C., dated as of February 8, 2006.

(i) “Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible.

(j) “Material Adverse Effect” means, with respect to any party, any event or condition that has had or could reasonably be expected to (i) have a material adverse effect on the financial condition, results of operations or business of such party, (ii) result in a breach or violation of any representation, warranty, covenant or condition contained in this Agreement as a result of which a party has, or with notice, the lapse of time or both, is likely to have, the right to terminate this Agreement or (ii) impair or affect adversely such party’s ability to perform its obligations under this Agreement or impair or delay completion of the transactions contemplated hereby.

(k) “CCE Purchase Agreement” means the Purchase and Sale Agreement, dated as of September 14, 2006, among ETP and the Class B Members of CCE Holdings, LLC.

ARTICLE 2

CONTRIBUTIONS, ACKNOWLEDGMENTS AND DISTRIBUTIONS

Section 2.1 Contribution of IDR Interest to ETE. Subject to the terms and conditions hereof, ETI hereby agrees to contribute, grant, bargain, convey, assign, transfer, set over and deliver to ETE, its successors and assigns, for their use forever, all right, title and interest in and to the IDR Interest owned by ETI as a contribution to the capital of ETE and ETE hereby agrees to accept such IDR Interest as a contribution to the capital of ETE.

Section 2.2 Issuance of Class C Units and Assumption of Loan Agreement and ETP Promissory Note. Subject to the terms and conditions hereof, ETE hereby agrees to issue, grant, bargain, convey, assign, transfer, set over and deliver to ETI the Class C Units and to accept and assume the Loan Agreement and all of the rights and obligations of ETI arising out of or related to the Loan Agreement in exchange for the contribution of the IDR Interest by ETI

and ETI hereby agrees to accept the Class C Units in exchange for its capital contribution of the IDR Interest to ETE.

Section 2.3 Certificate Legends. The certificates evidencing the Class C Units delivered pursuant to Section 2.2 shall bear a legend substantially in the form set forth below and containing such other information as ETE may deem necessary or appropriate:

ARTICLE 3

CLOSING

Section 3.1 Time and Place. Subject to the terms and conditions hereof, the closing of the transactions contemplated hereby (the “Closing”) shall be held at the offices of Vinson & Elkins L.L.P., 2500 First City Tower, 1001 Fannin, Houston, Texas 77002 at 3:00 p.m., Houston time, immediately following the satisfaction or waiver of the conditions contained in Article 7 or at such other place or time as the parties hereto may mutually agree. The date of the Closing is referred to herein as the “Closing Date.”

Section 3.2 Deliveries at the Closing. At the Closing, the following shall occur:

(a) ETI shall execute and deliver to ETE duly executed unit certificates or unit certificates endorsed in blank whereby the IDR Interest is transferred to ETE;

(b) ETE shall execute and deliver Amendment No. 1 and shall deliver to ETI the Class C Units;

(c) ETI shall deliver to ETE an officer’s certificate, dated the Closing Date, and executed by ETI, reasonably satisfactory in form and substance to ETE, as to the matters set forth in Sections 7.1(a) and (b);

(d) ETE shall deliver to ETI an officer’s certificate, dated the Closing Date, and executed by ETE, reasonably satisfactory in form and substance to ETI, as to the matters set forth in Sections 7.2(a) and (b);

(e) ETI and ETE shall execute and deliver to the other counterparts of the form of registration rights agreement attached as Exhibit B;

(f) ETI shall deliver an executed consent of the lenders under the Loan Agreement, approving, ratifying and consenting to the assignment and assumption set forth in Section 2.2;

(g) ETI shall deliver to ETE Investor Representation Letters, duly executed by each of ETI’s limited and general partners, in the form attached hereto as Exhibit C; and

(h) Each Party shall execute such additional documents as the other Party shall reasonably request to effectuate the transactions contemplated hereby.

ARTICLE 4

REPRESENTATIONS AND WARRANTIES OF ETI

ETI hereby represents and warrants to ETE that the statements contained in this Article 4 are correct and complete as of the date hereof.

Section 4.1 Existence. ETI (i) is a limited partnership duly organized, legally existing and in good standing under the laws of the State of Delaware and (ii) has all requisite power and authority, and has all governmental licenses, authorizations, consents and approvals necessary, to own, lease, use and operate its Properties and carry on its business as its business is now being conducted, except where the failure to obtain such licenses, authorizations, consents and approvals would not be reasonably likely to have a Material Adverse Effect.

Section 4.2 Authority. ETI has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; and the execution, delivery and performance by ETI of this Agreement has been duly authorized by all necessary action on its part; and this Agreement constitutes the legal, valid and binding obligations of ETI, enforceable in accordance with its terms.

Section 4.3 Approvals. Other than consents that have been obtained, ETI is not required to obtain any authorization, consent, approval, waiver, license, qualification or written exemption from, nor make any filing, declaration, qualification or registration with, any court or governmental agency or body or any stock exchange authority or self regulatory organization (each, a “Governmental Authority”) or any other Person to consummate the contribution and delivery of the IDR Interest being contributed by ETI to ETE or in connection with the execution, delivery or performance by ETI of this Agreement.

Section 4.4 No Breach. The execution and delivery of this Agreement, the compliance by ETI with all the provisions of, and the performance by ETI of its obligations under, this Agreement, and the consummation of the transactions contemplated in this Agreement will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, (i) the constitutive documents of ETI, (ii) any instrument, contract or other agreement to which ETI is a party or by which ETI is bound or to which any of its Properties or assets may be bound or subject, in each case, the breach or violation of which or default under which would be reasonably expected to have a Material Adverse Effect on the ability of ETI to comply with its obligations hereunder, or (iii) any law or statute or any order, rule or regulation of any Governmental Authority, in each case having jurisdiction over ETI or any of its properties.

Section 4.5 Financial Statements. ETI’s unaudited financial statements and any notes thereto or schedules included therein (a) were prepared in accordance with generally accepted accounting principles applied on a consistent basis during the periods involved (except

as may be indicated in the notes thereto), and (b) fairly present (subject to normal, recurring and year-end audit adjustments) in all material respects the consolidated financial position and status of the business of ETI as of the dates thereof and the consolidated results of its operations and cash flows for the periods then ended.

Section 4.6 No Material Adverse Changes. Since the date of ETI’s most recent balance sheet information, ETI has conducted its business in the ordinary course, consistent with past practice, and there has been no change, event, occurrence, fact, circumstance or condition that has had or would be reasonably likely to have a Material Adverse Effect on the assets, liabilities, financial condition, business, operations or affairs of ETI.

Section 4.7 Good Title. ETI is the record and beneficial owner of, and has good and marketable title to, the IDR Interest, free and clear of all pledges, liens, claims, encumbrances, options, voting trusts or agreements, proxies or other claims or charges or adverse interests of any nature whatsoever (other than resulting from this Agreement, the ETP GP Partnership Agreement, the ETP GP LLC Agreement or the Loan Agreement).

Section 4.8 Nature of the Investor. ETI (a) is an “accredited investor” as defined in Rule 501(a) of Regulation D promulgated under the Act, (b) is able to bear the economic risk of losing its entire investment in the Class C Units, and (c) has knowledge and experience in financial and business matters such that it is capable of evaluating the risks and merits of this investment.

Section 4.9 Investment. ETI is acquiring the Class C Units for its own account, and not with a view to any distribution, resale, subdivision, or fractionalization thereof in violation of the Securities Act or any other applicable domestic securities law, and ETI has no present plans to enter into any contract, undertaking, agreement or arrangement for any such distribution, resale, subdivision, or fractionalization of the Class C Units in violation of the Securities Act or any other applicable domestic securities law. ETI acknowledges and agrees that, based in part upon its representations contained herein and in reliance upon applicable exemptions, the purchase and sale of the Class C Units has not been registered under the Act or the securities laws of any other domestic or foreign jurisdiction and that accordingly, the Class C Units may not be offered for sale, sold, or otherwise transferred in whole or in part, except in accordance with the terms of the Partnership Agreement and in compliance with all applicable laws, including securities laws, except that the Class C Units may be pledged in a bona fide transaction.

Section 4.10 Receipt of Information. ETI has carefully reviewed the documents filed by ETE with the Securities and Exchange Commission (the “Commission”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) within the 18 months prior to the date of this Agreement, including ETE’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, current reports on Form 8-K and other filings (the “Partnership Information”) and acknowledges that ETE has provided to ETI or its representatives all agreements, documents, records and books that ETI or its representatives have requested relating to an investment in ETE.

ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF ETE

ETE hereby represents and warrants to ETI that the statements contained in this Article 5 are correct and complete as of the date hereof.

Section 5.1 Existence. ETE (i) is a limited partnership duly organized, legally existing and in good standing under the laws of the State of Delaware and (ii) has all requisite power and authority, and has all governmental licenses, authorizations, consents and approvals necessary, to own, lease, use and operate its Properties and carry on its business as its business is now being conducted, except where the failure to obtain such licenses, authorizations, consents and approvals would not be reasonably likely to have a Material Adverse Effect.

Section 5.2 Valid Issuance of Purchased Units. ETE has taken all necessary action to approve and adopt Amendment No. 1 as an amendment to the Third Amended and Restated Agreement of Limited Partnership of ETE, as amended as of the date of this Agreement (the “Partnership Agreement”) and no approval of the limited partners of ETE is necessary for the approval and adoption of Amendment No. 1. At the Closing, Amendment No. 1 will be duly executed, delivered and adopted by ETE as an amendment to the Partnership Agreement. ETI, when such Class C Units are delivered as provided in this Agreement, will be entitled to the rights of a unitholder of limited partner interests of ETE as conferred by the Partnership Agreement, as amended by Amendment No. 1, and applicable law. The offer and sale of the Class C Units and the limited partner interests represented thereby have been duly authorized by ETE and, when issued and delivered to ETI against payment therefor in accordance with the terms of this Agreement, will be validly issued, fully paid (to the extent required under the Partnership Agreement) and nonassessable (except as such nonassessability may be affected by such matters described under the caption “Description of Our Partnership Agreement—Limited Liability” in ETE’s Registration Statement on Form S-1 (File No. 333-128097).

Section 5.3 Authority. ETE has all necessary power and authority to execute, deliver and perform its obligations under this Agreement; and the execution, delivery and performance by ETE of this Agreement has been duly authorized by all necessary action on its part; and this Agreement constitutes the legal, valid and binding obligations of ETE, enforceable in accordance with its terms. No approval from the equity owners of ETE is required in connection with the transactions contemplated by this Agreement, other than the approval by the holders of Common Units of a proposal to convert the Class C Units into Common Units on a one-for-one basis as specified in Amendment No. 1 to the extent required under the rules of the New York Stock Exchange (the “Class C Unit Conversion”).

Section 5.4 Approvals. Other than the listing of the Class C Units on the New York Stock Exchange and the Class C Unit Conversion, ETE is not required to obtain any authorization, consent, approval, waiver, license, qualification or written exemption from, nor make any filing, declaration, qualification or registration with, any Governmental Authority or any other Person to consummate the sale and delivery of the Class C Units being sold by ETE to ETI or in connection with the execution, delivery or performance by ETE of this Agreement.

Section 5.5 No Breach. The execution and delivery of this Agreement, the compliance by ETE with all the provisions of, and the performance by ETE of its obligations under, this Agreement, and the consummation of the transactions contemplated in this Agreement will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, (i) the constitutive documents of ETE, (ii) any instrument, contract or other agreement to which ETE is a party or by which ETE is bound or to which any of its Properties or assets may be bound or subject, in each case, the breach or violation of which or default under which would be reasonably expected to have a Material Adverse Effect on the ability of ETE to comply with its obligations hereunder, or (iii) any law or statute or any order, rule or regulation of any Governmental Authority.

Section 5.6 Legal Proceedings. There are no legal or governmental proceedings pending to which ETE is a party or of which any property of ETE is the subject that, if determined adversely to ETE, would individually or in the aggregate have a Material Adverse Effect on ETE’s ability to perform its obligations under this Agreement, and, to the best of ETE’s knowledge, no such proceedings are threatened or contemplated by any such Governmental Authority or threatened by others.

Section 5.7 Seller Commission Documents. ETE has filed with the Commission all forms, registration statements, reports, schedules and statements required to be filed by it under the Exchange Act or the Securities Act within the 18 months prior to the date of this Agreement (all such documents, collectively the “Seller Commission Documents”). The Seller Commission Documents, including, without limitation, any audited or unaudited financial statements and any notes thereto or schedules included therein, at the time filed (in the case of registration statements, solely on the dates of effectiveness) (except to the extent corrected by a subsequently filed the Seller Commission Document filed prior to the date hereof) (a) complied as to form in all material respects with applicable accounting requirements and with the published rules and regulations of the Commission with respect thereto, (b) did not, at the time they were filed, or, if amended, as of the date of such amendment, contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading, (c) were prepared in accordance with generally accepted accounting principles applied on a consistent basis during the periods involved (except as may be indicated in the notes thereto or, in the case of unaudited statements, as permitted by the applicable rules and regulations of the Commission), and (d) fairly present (subject in the case of unaudited statements to normal, recurring and year-end audit adjustments) in all material respects the consolidated financial position and status of the business of ETE as of the dates thereof and the consolidated results of its operations and cash flows for the periods then ended.

Section 5.8 No Material Adverse Changes. Except as disclosed in the documents filed by ETE under the Exchange Act, since the date of ETE’s most recent Form 8-K (to the extent it contains financial results and balance sheet information) or Form 10-Q filing with the Commission, ETE and its subsidiaries have conducted their respective businesses in the ordinary course, consistent with past practice, and there has been no change, event, occurrence, fact, circumstance or condition that has had or would be reasonably likely to have a Material Adverse Effect on the assets, liabilities, financial condition, business, operations or affairs of ETE and its subsidiaries, taken as a whole.

ARTICLE 6

COVENANTS

Section 6.1 Other Agreements.

(a) ETE hereby agrees to prepare and cause to be filed as soon as reasonably practicable, and in any event within 30 days from the date hereof, with the Commission a proxy statement (the “Proxy Statement”) providing for the submission for approval of the Class C Unit Conversion by ETE’s common unitholders. As promptly as practicable after comments are received from the Commission thereon and after the furnishing by ETE of all information required to be contained therein, ETE shall, in consultation with ETI, prepare and the Company shall file the definitive, Proxy Statement with the Commission. The Company shall notify ETI promptly of the receipt of any comments from the Commission or its staff and of any request by the Commission or its staff for amendments or supplements to the Proxy Statement or for additional information and shall consult with ETI regarding all correspondence between the ETE and the Commission, with respect to the Proxy Statement. ETE shall use reasonable best efforts to have the Proxy Statement cleared by the Commission and shall thereafter mail to ETE’s unitholders as promptly as possible the Proxy Statement and all other proxy materials for such meeting. The general partner of ETE (the “ETE General Partner”) shall take all actions in accordance with applicable law and ETE’s constitutive documents, to duly call, give notice of, convene and hold as promptly as practicable a meeting of ETE’s unitholders for the purpose of considering and voting upon the conversion of the Class C Units to Common Units on a one-for-one basis as specified in Amendment No. 1. To the fullest extent permitted by applicable law, the ETE General Partner shall recommend the approval of such conversion and include such recommendation in the Proxy Statement. ETE agrees to use its best efforts to cause the listing on the NYSE of the Common Units issuable upon conversion of the Class C Units.

(b) Each party agrees that it will indemnify and hold harmless the other party from and against any and all claims, demands, or liabilities for broker’s, finder’s, placement, or other similar fees or commissions incurred by such party or alleged to have been incurred by such party in connection with the purchase of the Class C Units or the consummation of the transactions contemplated by this Agreement.

Section 6.2 Information. ETI shall supply such information with respect to itself, its directors, officers and shareholders as ETE may reasonably request for the purpose of preparation of the Proxy Statement. ETE shall supply to ETI such information with respect to itself, its directors, officers and unitholders and such other matters as ETI may reasonably request for the purpose of preparation of any notice, form or other documents required to be filed with any Governmental Authority or delivered to ETI’s partners in connection with the transaction contemplated by this Agreement.

Section 6.3 Further Assurances. Each party agrees to execute, acknowledge and deliver such further instruments and to do all such other acts as may be necessary or appropriate to carry out the purposes and intent of this Agreement.

ARTICLE 7

CONDITIONS

Section 7.1 Mutual Conditions. The respective obligations of each Party to consummate the transactions contemplated by this Agreement at the Closing Date shall be subject to (i) the CCE Purchase Agreement being in full force and effect and (ii) all conditions to closing under the CCE Purchase Agreement having been satisfied, other than the delivery of any closing items designated under Section 2.4 of the CCE Purchase Agreement.

Section 7.2 Conditions to Obligations of ETE. Notwithstanding any other provision of this Agreement, the obligations of ETE to effect the transactions contemplated by this Agreement shall be subject to the fulfillment at or prior to the Closing Date of the following conditions:

(a) the representations and warranties of ETI contained in this Agreement shall have been true and correct in all material respects as of the Closing Date, with the same effect as if made on and as of the Closing Date;

(b) the agreements and covenants of the ETI to be complied with or performed on or before the Closing Date pursuant to the terms hereof shall have been duly complied with or performed; and

(c) the Unit Purchase Agreement between ETE and ETP, dated as of November 1, 2006 (the “ETP Purchase Agreement”) shall be in full force and effect, at the Closing Date, and all conditions to closing under the Purchase Agreement shall have been satisfied other than the delivery of closing items under Sections 2.02 and 2.03 of the ETP Purchase Agreement.

Section 7.3 Conditions to Obligations of ETI. Notwithstanding any other provision of this Agreement, the obligations of ETI to effect the transactions contemplated by this Agreement shall be subject to the fulfillment at or prior to the Closing Date of the following conditions:

(a) the representations and warranties of ETE contained in this Agreement shall have been true and correct in all material respects as of the Closing Date, with the same effect as if made on and as of the Closing Date; and

(b) the agreements and covenants of ETE to be complied with or performed on or before the Closing Date pursuant to the terms hereof shall have been duly complied with or performed.

ARTICLE 8

MISCELLANEOUS

Section 8.1 Costs. Each party hereto shall be responsible for the payment of the costs and expenses incurred by it in connection with the negotiation, execution, delivery and performance of this Agreement and the transactions contemplated hereby.

Section 8.2 Headings; References; Interpretation. All Article and Section headings in this Agreement are for convenience only and shall not be deemed to control or affect the meaning or construction of any of the provisions hereof. The words “hereof,” “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole, including, without limitation, all Exhibits attached hereto, and not to any particular provision of this Agreement. All references herein to Articles, Sections and Exhibits shall, unless the context requires a different construction, be deemed to be references to the Articles and Sections of this Agreement and the Exhibits attached hereto, and all such Exhibits attached hereto are hereby incorporated herein and made a part hereof for all purposes. All personal pronouns used in this Agreement, whether used in the masculine, feminine or neuter gender, shall include all other genders, and the singular shall include the plural and vice versa. The use herein of the word “including” following any general statement, term or matter shall not be construed to limit such statement, term or matter to the specific items or matters set forth immediately following such word or to similar items or matters, whether or not non-limiting language (such as “without limitation,” “but not limited to,” or words of similar import) is used with reference thereto, but rather shall be deemed to refer to all other items or matters that could reasonably fall within the broadest possible scope of such general statement, term or matter.

Section 8.3 Successors and Assigns. The Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

Section 8.4 No Third Party Rights. The provisions of this Agreement are intended to bind the Parties as to each other and are not intended to and do not create rights in any other person or confer upon any other person any benefits, rights or remedies and no person is or is intended to be a third party beneficiary of any of the provisions of this Agreement.

Section 8.5 Counterparts. This Agreement may be executed in any number of counterparts, all of which together shall constitute one agreement binding on the parties hereto.

Section 8.6 Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware applicable to contracts made and to be performed wholly within such state without giving effect to any otherwise applicable conflict of law principles thereof.

Section 8.7 Severability. If any of the provisions of this Agreement are held by any court of competent jurisdiction to contravene, or to be invalid under, the laws of any political body having jurisdiction over the subject matter hereof, such contravention or invalidity shall not invalidate the entire Agreement. Instead, this Agreement shall be construed as if it did not contain the particular provision or provisions held to be invalid and an equitable adjustment shall be made and necessary provision added so as to give effect to the intention of the Parties as expressed in this Agreement at the time of execution of this Agreement.

Section 8.8 Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the Parties. Each such instrument shall be reduced to writing and shall be designated on its face as an Amendment to this Agreement.

Section 8.9 Integration. This Agreement and the instruments referenced herein supersede all previous understandings or agreements among the Parties, whether oral or written, with respect to their subject matter. This document and such instruments contain the entire understanding of the Parties with respect to the subject matter hereof and thereof. No understanding, representation, promise or agreement, whether oral or written, is intended to be or shall be included in or form part of this Agreement unless it is contained in a written amendment hereto executed by the parties hereto after the date of this Agreement.

Section 8.10 Survival of Representations and Warranties. The representations and warranties made in this Contribution Agreement shall survive the Effective Time for a period of one year. This Section 8.10 shall not limit the term of any covenant or agreement which by its terms contemplates performance after the Closing Date.

Section 8.11 Deed; Bill of Sale; Assignment. To the extent required and permitted by applicable law, this Agreement shall also constitute a “deed,” “bill of sale” or “assignment” of the assets and interests referenced herein.

IN WITNESS WHEREOF, this Agreement has been duly executed by the parties hereto as of the date first above written.


ENERGY TRANSFER EQUITY, L.P.

By:		LE GP, LLC, its general partner

By:		/s/ John W. McReynolds
Name:		John W. McReynolds
Title:		President

ENERGY TRANSFER INVESTMENTS, L.P.

By:		ETI GP, LLC, its general partner

By:		/s/ John W. McReynolds
Name:		John W. McReynolds
Title:		President

SIGNATURE PAGE TO

CONTRIBUTION, ASSUMPTION

AND

CONVEYANCE AGREEMENT

Exhibit A

Amendment No. 1 to ETE Partnership Agreement

Exhibit B

Form of Registration Rights Agreement

Exhibit C

Investor Representation Letter

November , 2006

Energy Transfer Equity, L.P.

2828 Woodside

Dallas, Texas 75204

Ladies and Gentlemen:

Reference is hereby made to that certain Contribution, Assumption and Conveyance Agreement, dated as of November 1, 2006 (the “Contribution Agreement”), by and between Energy Transfer Equity, L.P., a Delaware limited partnership (“ETE”) and Energy Transfer Investments, L.P., a Delaware limited partnership (“ETI”). Capitalized terms that are used but not defined herein are used with the meanings assigned to them in the Contribution Agreement.

The obligation of ETE to consummate the transactions contemplated by the Contribution Agreement is subject to the execution and delivery of this letter by the undersigned to ETE. In connection with the Contribution Agreement, the undersigned hereby represents and warrants to ETE as follows:

(a) the undersigned is an “accredited investor” as such term is defined in Rule 501 (but without regard to subsection (a)(4) thereof) promulgated under the Securities Act of 1933, as amended (the “Securities Act”);

(b) the undersigned is acquiring the Class C Units issuable to the undersigned upon consummation of the Contribution Agreement for investment and for the undersigned’s own account and not with a view to, or for resale in connection with, any distribution;

(c) the undersigned understands that such Class C Units have not been registered under the Securities Act or under any state securities or blue sky laws, and, as a result, are subject to substantial restrictions on transfer;

(d) the undersigned acknowledges that appropriate legends will be placed on the certificates representing such Class C Units indicating the restrictions on transfer of such Class C Units;

(e) the undersigned acknowledges that such Class C Units must be held indefinitely unless subsequently registered under the Securities Act and any applicable state securities or blue sky laws, or sold or otherwise transferred pursuant to exemptions from registration under the Securities Act and/or such state securities laws, and that the undersigned has no obligation to register such Class C Units.

Very truly yours,

Registration Rights Agreement

Exhibit 10.38

REGISTRATION RIGHTS AGREEMENT

BY AND AMONG

ENERGY TRANSFER EQUITY, L.P.,

AND

ENERGY TRANSFER INVESTMENTS, L.P.

REGISTRATION RIGHTS AGREEMENT

THIS REGISTRATION RIGHTS AGREEMENT (this “Agreement”) is made and entered into as of November 1, 2006, by and among ENERGY TRANSFER EQUITY, L.P., a Delaware limited partnership (“ETE”), and ENERGY TRANSFER INVESTMENTS, L.P., a Delaware limited partnership (“ETI”).

This Agreement is made in connection with the Closing of the issuance and sale of the Class C Units to ETI pursuant to the Contribution, Assumption and Conveyance Agreement, dated as of November 1, 2006, by and between ETE and ETI (the “Contribution Agreement”). ETE has agreed to enter into this Agreement pursuant to Section 3.2(f) of the Contribution Agreement. In consideration of the mutual covenants and agreements set forth herein and for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged by each party hereto, the parties hereby agree as follows:

ARTICLE I.

DEFINITIONS

Section 1.01 Definitions. Capitalized terms used herein without definition shall have the meanings given to them in the Purchase Agreement. The terms set forth below are used herein as so defined:

“Contribution Agreement” has the meaning specified therefor in the Recital of this Agreement.

“Conversion Units” means the Common Units issuable upon conversion of the Class C Units.

“Effectiveness Period” has the meaning specified therefore in Section 2.01(a) of this Agreement.

“ETP” means Energy Transfer Partners, L.P., a Delaware limited partnership.

“Holder” means the record holder of any Registrable Securities.

“Losses” has the meaning specified therefor in Section 2.07(a) of this Agreement.

“Managing Underwriter” means, with respect to any Underwritten Offering, the book running lead manager of such Underwritten Offering.

“Registrable Securities” means the Conversion Units until such time as such securities cease to be Registrable Securities pursuant to Section 1.02 hereof.

“Registration Expenses” has the meaning specified therefor in Section 2.06(a) of this Agreement.

“Selling Expenses” has the meaning specified therefor in Section 2.06(a) of this Agreement.

“Selling Holder” means a Holder who is selling Registrable Securities pursuant to a registration statement.

“Shelf Registration” has the meaning specified therefor in Section 2.01(a) of this Agreement.

“Shelf Registration Statement” has the meaning specified therefor in Section 2.01(a) of this Agreement.

“Underwritten Offering” means an offering (including an offering pursuant to a Shelf Registration Statement) in which Common Units are sold to an underwriter on a firm commitment basis for reoffering to the public or an offering that is a “bought deal” with one or more investment banks.

Section 1.02 Registrable Securities. Any Registrable Security will cease to be a Registrable Security when (a) a registration statement covering such Registrable Security has been declared effective by the Commission and such Registrable Security has been sold or disposed of pursuant to such effective registration statement; (b) such Registrable Security has been disposed of pursuant to any section of Rule 144 (or any similar provision then in force under the Securities Act); (c) such Registrable Security is held by ETE or one of its subsidiaries; or (d) such Registrable Security is eligible for resale under Rule 144(k) under the Securities Act.

ARTICLE II.

REGISTRATION RIGHTS

Section 2.01 Shelf Registration.

(a) Shelf Registration. As soon as practicable following the Closing of the purchase of the Class C Units pursuant to the terms of the Purchase Agreement, but in any event within 120 days of the Closing, ETE shall prepare and file a registration statement under the Securities Act to permit the public resale of the Registrable Securities from time to time as permitted by Rule 415 of the Securities Act (the “Shelf Registration Statement”). ETE shall use its commercially reasonable efforts to cause the Shelf Registration Statement to become effective no later than 180 days after the date of the Closing (the “Shelf Registration”). The Shelf Registration Statement filed pursuant to this Section 2.01(a) shall be on such appropriate registration form of the Commission as shall be selected by ETE; provided, however, that if a prospectus supplement will be used in connection with the marketing of an Underwritten Offering from the Shelf Registration Statement and the Managing Underwriter at any time shall notify ETE in writing that, in the sole judgment of such Managing Underwriter, inclusion of detailed information to be used in such prospectus supplement is of material importance to the success of the Underwritten Offering of such Registrable Securities, ETE shall use its commercially reasonable efforts to include such information in such a prospectus supplement. ETE will cause the Shelf Registration Statement filed pursuant to this Section 2.01(a) to be continuously effective under the Securities Act until all Registrable Securities covered by the Shelf Registration Statement have been distributed in the manner set forth and as contemplated in the Shelf Registration Statement or there are no longer any Registrable Securities outstanding (the “Effectiveness Period”). The Shelf Registration Statement when declared effective

(including the documents incorporated therein by reference) will comply as to form with all applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading.

(b) Delay Rights. Notwithstanding anything to the contrary contained herein, ETE may, upon written notice to any Selling Holder whose Registrable Securities are included in the Shelf Registration Statement, suspend such Selling Holder’s use of any prospectus which is a part of the Shelf Registration Statement (in which event the Selling Holder shall discontinue sales of the Registrable Securities pursuant to the Shelf Registration Statement) if ETE or ETP, as the case may be, (i) is pursuing an acquisition, merger, reorganization, disposition or other similar transaction and determines in good faith that its ability to pursue or consummate such a transaction would be materially adversely affected by any required disclosure of such transaction in the Shelf Registration Statement or (ii) has experienced some other material non-public event the disclosure of which at such time, in the good faith judgment of ETE or ETP, as applicable, would materially adversely affect ETE or ETP, as applicable. Upon disclosure of such information or the termination of the condition described above, ETE shall provide prompt notice to the Selling Holders whose Registrable Securities are included in the Shelf Registration Statement, and shall promptly terminate any suspension of sales it has put into effect and shall take such other actions to permit registered sales of Registrable Securities as contemplated in this Agreement.

Section 2.02 Underwritten Offering. In the event that a Selling Holder elects to dispose of Registrable Securities under the Shelf Registration Statement pursuant to an Underwritten Offering, ETE shall enter into an underwriting agreement in customary form with the Managing Underwriter or Underwriters, which shall include, among other provisions, indemnities to the effect and to the extent provided in Section 2.07, and shall take all such other reasonable actions as are requested by the Managing Underwriter in order to expedite or facilitate the registration and disposition of the Registrable Securities. In connection with any Underwritten Offering under this Agreement, ETE shall be entitled to select the Managing Underwriter or Underwriters. No Selling Holder may participate in such Underwritten Offering unless such Selling Holder agrees to sell its Registrable Securities on the basis provided in such underwriting agreement and completes and executes all questionnaires, powers of attorney, indemnities and other documents reasonably required under the terms of such underwriting agreement. Each Selling Holder may, at its option, require that any or all of the representations and warranties by, and the other agreements on the part of, ETE to and for the benefit of such underwriters also be made to and for such Selling Holder’s benefit and that any or all of the conditions precedent to the obligations of such underwriters under such underwriting agreement also be conditions precedent to its obligations. No Selling Holder shall be required to make any representations or warranties to or agreements with ETE or the underwriters other than representations, warranties or agreements regarding such Selling Holder and its ownership of the securities being registered on its behalf and its intended method of distribution and any other representation required by law. If any Selling Holder disapproves of the terms of an underwriting, such Selling Holder may elect to withdraw therefrom by notice to ETE and the Managing Underwriter; provided, however, that such withdrawal must be made up to and including the time of pricing of such offering to be effective. No such withdrawal or abandonment shall affect ETE’s obligation to pay Registration Expenses.

Section 2.03 Registration Procedures. In connection with its obligations contained in Section 2.01, ETE will, as expeditiously as possible:

(a) prepare and file with the Commission such amendments and supplements to the Shelf Registration Statement and the prospectus used in connection therewith as may be necessary to keep the Shelf Registration Statement effective for the Effectiveness Period and as may be necessary to comply with the provisions of the Securities Act with respect to the disposition of all securities covered by the Shelf Registration Statement;

(b) furnish to each Selling Holder (i) as far in advance as reasonably practicable before filing the Shelf Registration Statement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including furnishing or making available exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such information prior to filing the Shelf Registration Statement or supplement or amendment thereto, and (ii) such number of copies of the Shelf Registration Statement and the prospectus included therein and any supplements and amendments thereto as such Persons may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities covered by such Shelf Registration Statement or other registration statement;

(c) if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by the Shelf Registration Statement under the securities or blue sky laws of such jurisdictions as the Selling Holders or, in the case of an Underwritten Offering, the Managing Underwriter, shall reasonably request, provided that ETE will not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action which would subject it to general service of process in any such jurisdiction where it is not then so subject;

(d) promptly notify each Selling Holder and each underwriter, at any time when a prospectus relating thereto is required to be delivered under the Securities Act, of (i) the filing of the Shelf Registration Statement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Shelf Registration Statement, when the same has become effective; and (ii) any written comments from the Commission with respect to any filing referred to in clause (i) and any written request by the Commission for amendments or supplements to the Shelf Registration Statement or any prospectus or prospectus supplement thereto;

(e) immediately notify each Selling Holder and each underwriter, at any time when a prospectus relating thereto is required to be delivered under the Securities Act, of (i) the happening of any event as a result of which the prospectus or prospectus supplement contained in the Shelf Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing; (ii) the issuance or threat of issuance by the Commission of any stop order suspending the effectiveness of the

Shelf Registration Statement, or the initiation of any proceedings for that purpose; or (iii) the receipt by ETE of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, ETE agrees to as promptly as practicable amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to take such other action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto;

(f) furnish to each Selling Holder copies of any and all transmittal letters or other correspondence with the Commission or any other governmental agency or self-regulatory body or other body having jurisdiction (including any domestic or foreign securities exchange) relating to such offering of Registrable Securities;

(g) in the case of an Underwritten Offering, furnish upon request, (i) an opinion of counsel for ETE, dated the effective date of the closing under the underwriting agreement, and (ii) a “comfort letter”, dated the effective date of the applicable registration statement or the date of any amendment or supplement thereto and a letter of like kind dated the date of the closing under the underwriting agreement, in each case, signed by the independent public accountants who have certified ETE’s financial statements included or incorporated by reference into the applicable registration statement, and each of the opinion and the “comfort letter” shall be in customary form and covering substantially the same matters with respect to such registration statement (and the prospectus and any prospectus supplement included therein) and as are customarily covered in opinions of issuer’s counsel and in accountants’ letters delivered to the underwriters in Underwritten Offerings of securities, and such other matters as such underwriters may reasonably request;

(h) otherwise use its commercially reasonable efforts to comply with all applicable rules and regulations of the Commission, and make available to its security holders, as soon as reasonably practicable, an earnings statement covering the period of at least 12 months, but not more than 18 months, beginning with the first full calendar month after the effective date of such registration statement, which earnings statement shall satisfy the provisions of Section 11(a) of the Securities Act and Rule 158 promulgated thereunder;

(i) make available to the appropriate representatives of the Managing Underwriter and Selling Holders access to such information and ETE personnel as is reasonable and customary to enable such parties to establish a due diligence defense under the Securities Act; provided that ETE need not disclose any information to any such representative unless and until such representative has entered into a confidentiality agreement with ETE;

(j) cause all such Registrable Securities registered pursuant to this Agreement to be listed on each securities exchange or nationally recognized quotation system on which similar securities issued by ETE are then listed;

(k) use its commercially reasonable efforts to cause the Registrable Securities to be registered with or approved by such other governmental agencies or authorities as may be necessary by virtue of the business and operations of ETE to enable the Selling Holders to consummate the disposition of such Registrable Securities;

(l) provide a transfer agent and registrar for all Registrable Securities covered by such registration statement not later than the effective date of such registration statement; and

(m) enter into customary agreements and take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, in order to expedite or facilitate the disposition of such Registrable Securities.

Each Selling Holder, upon receipt of notice from ETE of the happening of any event of the kind described in subsection (e) of this Section 2.03, shall forthwith discontinue disposition of the Registrable Securities until such Selling Holder’s receipt of the copies of the supplemented or amended prospectus contemplated by subsection (e) of this Section 2.03 or until it is advised in writing by ETE that the use of the prospectus may be resumed, and has received copies of any additional or supplemental filings incorporated by reference in the prospectus, and, if so directed by ETE, such Selling Holder will, or will request the managing underwriter or underwriters, if any, to deliver to ETE (at ETE’s expense) all copies in their possession or control, other than permanent file copies then in such Selling Holder’s possession, of the prospectus covering such Registrable Securities current at the time of receipt of such notice.

Section 2.04 Cooperation by Holders. ETE shall have no obligation to include in the Shelf Registration Statement units of a Holder who has failed to timely furnish such information which, in the opinion of counsel to ETE, is reasonably required in order for the Shelf Registration Statement or any prospectus or prospectus supplement thereto, as applicable, to comply with the Securities Act.

Section 2.05 Restrictions on Public Sale by Holders of Registrable Securities. Each Holder of Registrable Securities who is included in the Shelf Registration Statement agrees not to effect any public sale or distribution of the Registrable Securities during the 120 calendar day period beginning on the date of a prospectus supplement filed with the Commission with respect to the pricing of an Underwritten Offering, provided that (i) ETE gives written notice to such Holder of the date of the commencement and termination of such period with respect to any such Underwritten Offering and (ii) the duration of the foregoing restrictions shall be no longer than the duration of the shortest restriction generally imposed by the underwriters on ETE or on the officers or directors or any other unitholder of ETE on whom a restriction is imposed.

Section 2.06 Expenses.

(a) Certain Definitions. “Registration Expenses” means all expenses incident to ETE’s performance under or compliance with this Agreement to effect the registration of Registrable Securities in a Shelf Registration, and the disposition of such securities, including, without limitation, all registration, filing, securities exchange listing and NYSE fees, all registration, filing, qualification and other fees and expenses of complying with securities or blue sky laws, fees of the National Association of Securities Dealers, Inc., transfer taxes and fees of

transfer agents and registrars, all word processing, duplicating and printing expenses, the fees and disbursements of counsel and independent public accountants for ETE, including the expenses of any special audits or “comfort letters” required by or incident to such performance and compliance. Except as otherwise provided in Section 2.07 hereof, ETE shall not be responsible for legal fees incurred by Holders in connection with the exercise of such Holders’ rights hereunder. In addition, ETE shall not be responsible for any “Selling Expenses,” which means all underwriting fees, discounts and selling commissions allocable to the sale of the Registrable Securities.

(b) Expenses. ETE will pay all Registration Expenses in connection with the Shelf Registration Statement filed pursuant to Section 2.01(a) of this Agreement, whether or not the Shelf Registration Statement becomes effective or any sale is made pursuant to the Shelf Registration Statement. Each Selling Holder shall pay all Selling Expenses in connection with any sale of its Registrable Securities hereunder.

Section 2.07 Indemnification.

(a) By ETE. In the event of a registration of any Registrable Securities under the Securities Act pursuant to this Agreement, ETE will indemnify and hold harmless each Selling Holder thereunder, its directors and officers of Registrable Securities thereunder and each Person, if any, who controls such Selling Holder or underwriter within the meaning of the Securities Act and the Exchange Act, against any losses, claims, damages, expenses or liabilities (including reasonable attorneys’ fees and expenses) (collectively, “Losses”), joint or several, to which such Selling Holder or underwriter or controlling Person may become subject under the Securities Act, the Exchange Act or otherwise, insofar as such Losses (or actions or proceedings, whether commenced or threatened, in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in the Shelf Registration Statement, any preliminary prospectus or final prospectus contained therein, or any amendment or supplement thereof, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein (in the case of a prospectus, in light of the circumstances under which they were made) not misleading, and will reimburse each such Selling Holder, its directors and officers, each such underwriter and each such controlling Person for any legal or other expenses reasonably incurred by them in connection with investigating or defending any such Loss or actions or proceedings; provided, however, that ETE will not be liable in any such case if and to the extent that any such Loss arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission so made in conformity with information furnished by such Selling Holder, such underwriter or such controlling Person in writing specifically for use in the Shelf Registration Statement or any prospectus contained therein or any amendment or supplement thereof. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of such Selling Holder or any such director, officer or controlling Person, and shall survive the transfer of such securities by such Selling Holder.

(b) By Each Selling Holder. Each Selling Holder agrees severally and not jointly to indemnify and hold harmless ETE, its directors and officers, and each Person, if any, who controls ETE within the meaning of the Securities Act or of the Exchange Act to the same extent as the foregoing indemnity from ETE to the Selling Holders, but only with respect to

information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in the Shelf Registration Statement or any prospectus contained therein or any amendment or supplement thereof relating to the Registrable Securities; provided, however, that the liability of each Selling Holder shall not be greater in amount than the dollar amount of the proceeds (net of any Selling Expenses) received by such Selling Holder from the sale of the Registrable Securities giving rise to such indemnification.

(c) Notice. Promptly after receipt by an indemnified party hereunder of notice of the commencement of any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party hereunder, notify the indemnifying party in writing thereof, but the omission so to notify the indemnifying party shall not relieve it from any liability which it may have to any indemnified party other than under this Section 2.07. In any action brought against any indemnified party, it shall notify the indemnifying party of the commencement thereof. The indemnifying party shall be entitled to participate in and, to the extent it shall wish, to assume and undertake the defense thereof with counsel reasonably satisfactory to such indemnified party and, after notice from the indemnifying party to such indemnified party of its election so to assume and undertake the defense thereof, the indemnifying party shall not be liable to such indemnified party under this Section 2.07 for any legal expenses subsequently incurred by such indemnified party in connection with the defense thereof other than reasonable costs of investigation and of liaison with counsel so selected; provided, however, that, (i) if the indemnifying party has failed to assume the defense and employ counsel or (ii) if the defendants in any such action include both the indemnified party and the indemnifying party and counsel to the indemnified party shall have concluded that there may be reasonable defenses available to the indemnified party that are different from or additional to those available to the indemnifying party, or if the interests of the indemnified party reasonably may be deemed to conflict with the interests of the indemnifying party, then the indemnified party shall have the right to select a separate counsel and to assume such legal defense and otherwise to participate in the defense of such action, with the reasonable expenses and fees of such separate counsel and other reasonable expenses related to such participation to be reimbursed by the indemnifying party as incurred. Notwithstanding any other provision of this Agreement, no indemnified party shall settle any action brought against it with respect to which it is entitled to indemnification hereunder without the consent of the indemnifying party, unless the settlement thereof imposes no liability or obligation on, and includes a complete and unconditional release from all liability of, the indemnifying party.

(d) Contribution. If the indemnification provided for in this Section 2.07 is held by a court or government agency of competent jurisdiction to be unavailable to ETE or any Selling Holder or is insufficient to hold them harmless in respect of any Losses, then each such indemnifying party, in lieu of indemnifying such indemnified party, shall contribute to the amount paid or payable by such indemnified party as a result of such Losses as between ETE on the one hand and such Selling Holder on the other, in such proportion as is appropriate to reflect the relative fault of ETE on the one hand and of such Selling Holder on the other in connection with the statements or omissions which resulted in such Losses, as well as any other relevant equitable considerations; provided, however, that in no event shall such Selling Holder be required to contribute an aggregate amount in excess of the dollar amount of proceeds (net of Selling Expenses) received by such Selling Holder from the sale of Registrable Securities giving rise to such indemnification. The relative fault of ETE on the one hand and each Selling Holder

on the other shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact has been made by, or relates to, information supplied by such party, and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The parties hereto agree that it would not be just and equitable if contributions pursuant to this paragraph were to be determined by pro rata allocation or by any other method of allocation which does not take account of the equitable considerations referred to in the first sentence of this paragraph. The amount paid by an indemnified party as a result of the Losses referred to in the first sentence of this paragraph shall be deemed to include any legal and other expenses reasonably incurred by such indemnified party in connection with investigating or defending any Loss which is the subject of this paragraph. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who is not guilty of such fraudulent misrepresentation.

(e) Other Indemnification. The provisions of this Section 2.07 shall be in addition to any other rights to indemnification or contribution which an indemnified party may have pursuant to law, equity, contract or otherwise.

Section 2.08 Rule 144 Reporting. With a view to making available the benefits of certain rules and regulations of the Commission that may permit the sale of the Registrable Securities to the public without registration, ETE agrees to use its commercially reasonable efforts to:

(a) Make and keep public information regarding ETE available, as those terms are understood and defined in Rule 144 of the Securities Act, at all times from and after the date hereof;

(b) File with the Commission in a timely manner all reports and other documents required of ETE under the Securities Act and the Exchange Act at all times from and after the date hereof; and

(c) So long as a Holder owns any Registrable Securities, furnish to such Holder forthwith upon request a copy of the most recent annual or quarterly report of ETE, and such other reports and documents so filed as such Holder may reasonably request in availing itself of any rule or regulation of the Commission allowing such Holder to sell any such securities without registration.

Section 2.09 Transfer or Assignment of Registration Rights. The rights to cause ETE to register Registrable Securities granted to ETI by ETE under this Article II may be transferred or assigned by ETI to one or more transferee(s) or assignee(s) of such Registrable Securities, provided that (a) ETE is given written notice prior to any said transfer or assignment, stating the name and address of each such transferee and identifying the securities with respect to which such registration rights are being transferred or assigned, and (b) each such transferee assumes in writing responsibility for its portion of the obligations of ETI under this Agreement.

Section 2.10 Information by Holder. Any Holder or Holders of Registrable Securities included in any registration statement shall promptly furnish to ETE such information regarding

such Holder or Holders and the distribution proposed by such Holder or Holders as ETE may reasonably request and as shall be required in connection with any registration, qualification or compliance referred to herein.

ARTICLE III.

MISCELLANEOUS

Section 3.01 Communications. All notices and other communications provided for or permitted hereunder shall be made in writing by facsimile, courier service or personal delivery:

(a) if to ETI, at 2828 Woodside Street, Dallas, Texas 75204,

(b) if to ETE, at 2828 Woodside Street, Dallas, Texas 75204, notice of which is given in accordance with the provisions of this Section 3.01.

All such notices and communications shall be deemed to have been received at the time delivered by hand, if personally delivered; when receipt acknowledged, if sent via facsimile or sent via Internet electronic mail; and when actually received, if sent by any other means.

Section 3.02 Successor and Assigns. This Agreement shall inure to the benefit of and be binding upon the successors and assigns of each of the parties, including subsequent Holders of Registrable Securities to the extent permitted herein.

Section 3.03 Assignment of Rights. All or any portion of the rights and obligations of ETI under this Agreement may be transferred or assigned by ETI only in accordance with Section 2.09 hereof.

Section 3.04 Recapitalization, Exchanges, etc. Affecting the Common Units. The provisions of this Agreement shall apply to the full extent set forth herein with respect to any and all units of ETE or any successor or assign of ETE (whether by merger, consolidation, sale of assets or otherwise) which may be issued in respect of, in exchange for or in substitution of, the Registrable Securities, and shall be appropriately adjusted for combinations, recapitalizations and the like occurring after the date of this Agreement.

Section 3.05 Specific Performance. Damages in the event of breach of this Agreement by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each such Person, in addition to and without limiting any other remedy or right it may have, will have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such Person from pursuing any other rights and remedies at law or in equity which such Person may have.

Section 3.06 Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same Agreement.

Section 3.07 Headings. The headings in this Agreement are for convenience of reference only and shall not limit or otherwise affect the meaning hereof.

Section 3.08 Governing Law. The laws of the State of Delaware shall govern this Agreement without regard to principles of conflict of laws.

Section 3.09 Severability of Provisions. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting or impairing the validity or enforceability of such provision in any other jurisdiction.

Section 3.10 Entire Agreement. This Agreement is intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein. There are no restrictions, promises, warranties or undertakings, other than those set forth or referred to herein with respect to the rights granted by ETE set forth herein. This Agreement supersedes all prior agreements and understandings between the parties with respect to such subject matter.

Section 3.11 Amendment. This Agreement may be amended only by means of a written amendment signed by ETE and the Holders of a majority of the then outstanding Registrable Securities; provided, however, that no such amendment shall materially and adversely affect the rights of any Holder hereunder without the consent of such Holder.

Section 3.12 No Presumption. In the event any claim is made by a party relating to any conflict, omission, or ambiguity in this Agreement, no presumption or burden of proof or persuasion shall be implied by virtue of the fact that this Agreement was prepared by or at the request of a particular party or its counsel.

[The remainder of this page is intentionally left blank.]

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above.


ENERGY TRANSFER INVESTMENTS, L.P.

By:		ETI GP, LLC, its general partner

By:		/s/ John W. McReynolds
		John W. McReynolds,
		President

ENERGY TRANSFER EQUITY, L.P.

By:		LE GP, L.L.C., its general partner

By:		/s/ John W. McReynolds
		John W. McReynolds, President

List of Subsidiaries

EXHIBIT 21.1

SUBSIDIARIES

1. Energy Transfer Partners, LLC, a Delaware limited liability company

2. Energy Transfer Partners GP, L.P., a Delaware limited partnership

3. Energy Transfer Partners, L.P., a Delaware limited partnership (2.0% general partner interest, 36.4 million Common Units, 26.1 million Class G Units and 100% of incentive distribution rights)

4. La Grange Acquisition, L.P., a Texas limited partnership, which does business as Energy Transfer Company through the following subsidiaries in which it holds a direct or indirect interest:

•

ET Company I, Ltd., a Texas limited partnership, holding a direct or indirect interest in the following:

•

Texas Energy Transfer Company, Ltd., a Texas limited partnership

•

Chalkley Transmission Company, Ltd., a Texas limited partnership

•

Whiskey Bay Gathering Company, Ltd., a Texas limited partnership

•

Whiskey Bay Gas Company, a Texas limited partnership

•

Ranger Pipeline, L.P., a Texas limited partnership, owning a partnership interest in the following:

•

Mountain Creek Joint Venture, a Texas general partnership

•

ETC Texas Pipeline, Ltd., a Texas limited partnership

•

ETC Texas Processing, Ltd., a Texas limited partnership

•

ETC Katy Pipeline, Ltd., a Texas limited partnership

•

ETC Gas Company Ltd., a Texas limited partnership, owning a partnership interest in the following:

•

ETC Marketing, Ltd., a Texas limited partnership

•

Oasis Pipeline, L.P., a Texas limited partnership

•

ETC Oasis, L.P., a Delaware limited partnership, owning a direct or indirect interest in the following:

•

Oasis Pipe Line Company, a Delaware corporation

•

Oasis Pipe Line Management Company, a Delaware corporation

•

Oasis Pipe Line Finance Company, a Delaware corporation

•

Oasis Partner Company, a Delaware corporation

•

Oasis Pipe Line Company Texas, L.P., a Texas limited partnership

•

Energy Transfer Fuel, LP, a Delaware limited partnership, owning a direct or indirect interest in the following:

•

ET Fuel Pipeline, L.P.

•

HP Houston Holdings, L.P., a Delaware limited partnership, owning a direct or indirect interest in the following:

•

HPL Consolidation LP, a Delaware limited partnership, owning a direct or indirect interest in the following:

•

HPL Asset Holdings LP, a Delaware limited partnership

•

HPL Leaseco LP, a Delaware limited partnership

•

HPL Resources Company LP, a Delaware limited partnership

•

HPL Gas Marketing LP, a Delaware limited partnership

•

Houston Pipe Line Company LP, a Delaware limited partnership, owning an interest in the following:

•

HPL Houston Pipe Line Company, LLC, a Delaware limited liability company

•

Mid-Texas Pipeline Company, a Texas general partnership

5. Heritage Operating L.P., a Delaware limited partnership, which does business under the following names:

•

Amogas

•

Archibald Propane

•

Balgas

•

Bi-State Propane

•

Blue Flame Gas

•

Blue Flame Gas of Charleston

•

Blue Flame Gas of Mt. Pleasant

•

Blue Flame Gas of Richmond

•

Boland Energy

•

C & D Propane

•

Carolane Propane

•

Clarendon Gas Co.

•

Corbin Gas

•

Covington Propane

•

Cumberland LP Gas

•

Custer Gas Service

•

Dawson Propane

•

E-Con Gas

•

Eaves Propane & Oil

•

Efird Gas Company

•

Energy North Propane

•

Fallsburg Gas Service

•

Flamegas Company

•

Foster’s Propane

•

Foust Fuels

•

Franconia Gas

•

Gas Service Company

•

Geldbach Petroleum

•

Gibson Propane

•

Green’s Fuel Gas Company

•

Greer Gas, L.P.

•

Guilford Gas

•

Harris Propane

•

Heritage Propane

•

Holton’s L.P. Gas

•

Horizon Gas

•

Houston County Propane

•

Hydratane of Athens

•

Ikard & Newsom

•

Ingas

•

J & J Propane Gas

•

John E. Foster & Son

•

Johnson Gas

•

Kingston Propane

•

Kirby’s Propane Gas

•

Lake County Gas

•

Lewis Gas Co.

•

Liberty Propane

•

Loyd Fuel

•

Lyons Gas

•

Manley Gas

•

Margas LP Service

•

Marlen Gas

•

Metro Lift Propane

•

Modern Propane Gas

•

Moore L.P. Gas

•

Mt. Pleasant Propane

•

Myers Propane Service

•

New Mexico Propane

•

Northern Energy

•

Northwestern Propane

•

Paradee Gas Company

•

Perkins Propane Gas

•

Pioneer Propane

•

ProFlame

•

Progas

•

Propane Gas Inc.

•

Quality Gas

•

Race City Propane

•

Rural Gas and Appliance

•

San Juan Propane

•

Sawyer Gas

•

ServiGas

•

ServiGas/Ikard & Newsom

•

Shaner Propane

•

Shaw L.P. Gas

•

Southern Gas Company

•

Thomas Gas Company

•

Trenton LP Gas

•

Tri-Cities Gas Company

•

Tri-Gas Propane Company

•

Tri-Gas of Benzie

•

Turner Propane

•

V-1 Propane

•

Vess Propane

•

Wakulla L.P.G.

•

Waynesville Gas Service

•

Young’s Propane

6. Titan Propane LLC, a Delaware limited liability company, which does business under the following names:

•

AAA Propane

•

Action Gas

•

Adobe Propane

•

Apache Gas

•

Arrow Propane

•

Ballard Gas Service

•

Blue Flame Gas

•

Braun Streat Propane

•

Briceton Lp

•

C F Lafountaine

•

Central Valley Propane

•

Coast Gas

•

Countryside Propane

•

County Propane

•

Delaware Valley Propane

•

Delta Propane

•

Eagle Valley Propane

•

Economy Propane

•

Empiregas

•

F K Gailey

•

Fayette County Propane

•

Flame Propane

•

Francis F Bezio

•

G & K Propane

•

Graves Propane

•

Hall’s Semple Propane

•

Interstate Gas

•

Keene Gas

•

L & K Propane

•

Lake Almanor Propane

•

Lehigh Valley Propane

•

Lone Pine Propane

•

Mar Gas

•

Michiana Gas

•

Mid Georgia Propane

•

Minns Gas LP

•

Mobile Gas

•

Mother Lode Propane

•

Mountain Propane

•

Myers/De’s

•

Pedley Propane

•

Pioneer Propane

•

Placer Propane

•

Propane Inc

•

Quality Propane

•

Ramona Propane

•

Rural Gas

•

Saratoga Propane

•

Shenandoah Valley Propane

•

Snyder Propane

•

Southeastern Propane

•

Southern Arizona Gas

•

SP Barron LP

•

Tecumseh LP

•

St Augustine Gas

•

Synergy Gas

•

Tappan Gas LP

•

Thomas Gas Company

•

Titan Propane

•

Town & Country

•

Tri County Bottled Gas Inc

•

Truckee Tahoe Propane

•

Vineyard Propane

•

Virginia Propane

•

Western LP

7. CCE Holdings, LLC, a Delaware limited liability company

8. Heritage Service Corp., a Delaware corporation, holding a direct interest in the following:

•

Heritage Energy Resources, L.L.C., an Oklahoma limited liability company

•

Heritage Energy Transfer Systems, L.L.C., a Delaware limited liability company

•

M-P Oils Ltd., an Alberta, Canada corporation, holding a direct or indirect interest in the following:

•

M-P Energy Partnership, an Alberta general partnership

•

Integrated Propane Services, Ltd., an Ontario corporation

•

EarthAmerica, L.L.C., a Delaware limited liability company, holding a direct or indirect interest in the following:

•

EarthAmerica of Texas, L.P., a Texas limited partnership

9. Titan Propane Services, Inc.

10. United Propane Exchange, L.L.C., a Delaware limited liability company

11. Heritage Holdings, Inc., a Delaware corporation

Certification of President and Chief Financial Officer pursuant to Section 302

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

AND CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

I have reviewed this annual report on Form 10-K of Energy Transfer Equity, L.P.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 29, 2006

/s/ John W. McReynolds

John W. McReynolds

President and Chief Financial Officer

Certification of President and Chief Financial Officer pursuant to Section 906

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-K for the year ended August 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 29, 2006

/s/ John W. McReynolds

John W. McReynolds

President and Chief Financial Officer

*	A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Equity, L.P.

Financial Statements of LE GP, L.L.C. as of August 31, 2006

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Members

LE GP, LLC

We have audited the accompanying consolidated balance sheet of LE GP, LLC (a Delaware limited liability company) and subsidiaries as of August 31, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of LE GP, LLC and subsidiaries as of August 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

November 20, 2006 (except for Note 12, as to which the date is November 28, 2006)

LE GP, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(in thousands)


	August 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	27,070
Marketable securities		2,817
Accounts receivable, net of allowance for doubtful accounts		675,545
Accounts receivable from related companies		481
Inventories		387,140
Deposits paid to vendors		87,806
Exchanges receivable		23,221
Price risk management assets		56,851
Prepaid expenses and other		42,549

Total current assets		1,303,480

PROPERTY, PLANT AND EQUIPMENT, net		3,748,614
LONG-TERM PRICE RISK MANAGEMENT ASSETS		2,192
ADVANCES TO AND INVESTMENT IN AFFILIATES		41,344
GOODWILL		633,998
INTANGIBLES AND OTHER ASSETS, net		186,708
OTHER LONG-TERM ASSETS		9,523

Total assets	$	5,925,859

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	603,662
Accounts payable to related companies		320
Exchanges payable		24,722
Customer advances and deposits		108,836
Accrued and other current liabilities		205,855
Price risk management liabilities		36,918
Deferred income taxes		629
Current maturities of long-term debt		40,607

Total current liabilities		1,021,549

LONG-TERM DEBT, less current maturities		3,276,146
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		2,843
DEFERRED INCOME TAXES		207,877
OTHER NON-CURRENT LIABILITIES		2,110
MINORITY INTERESTS		1,415,265

COMMITMENTS AND CONTINGENCIES

Total liabilities		5,925,790
MEMBERS’ EQUITY		69

Total liabilities and members’ equity	$	5,925,859

The accompanying notes are an integral part of this consolidated balance sheet.

LE GP, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET

AUGUST 31, 2006

(Dollars in thousands)

1.	OPERATIONS AND ORGANIZATION:

LE GP, LLC (“the Company”), a Delaware limited liability company, is the General Partner, with a 0.01% general partner interest of Energy Transfer Equity, L.P. (“ETE” or “the Partnership”). ETE is a Delaware limited partnership formed in August 2000. The Company also owns ETI GP, LLC, which owns the 0.01% general partner interest in Energy Transfer Investments, L.P. (“ETI”).

Energy Transfer Partners GP, LP (“ETP GP”) is the General Partner of Energy Transfer Partners, L.P. (“ETP”) and owns the 2% general partner interests of ETP. ETP is a publicly traded limited partnership.

ETE is the 100% owner of Energy Transfer Partners, L.L.C. (“ETP LLC”), which owns a 0.1% interest in ETP GP. ETE also owns 100% of ETP GP’s Class A limited partner interests and 50% of its Class B limited partner interest. The remaining 50% of ETP GP’s Class B limited partner interests are owned by ETI. On November 1, 2006, ETE acquired the remaining 50% of ETP GP’s Class B limited partner interests from ETI (see Note 11).

Balance Sheet Presentation

The accompanying consolidated balance sheet of LE GP, LLC and subsidiaries presented herein for the year ended August 31, 2006 has been prepared in accordance with accounting principles generally accepted in the United States of America. We consolidate all majority-owned and controlled subsidiaries, including ETE, ETI, ETI GP, LLC, ETP LLC, ETP and its subsidiaries, La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (referenced herein as “HOLP”), Heritage Holdings, Inc. (“HHI”) and Titan Energy Partners, L.P. (“Titan”). We recognize a minority interest liability for all partially-owned consolidated subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation.

Business Operations

LE GP, LLC conducts business operations only through the wholly-owned subsidiaries of ETP. In order to simplify the obligations of ETP under the laws of several jurisdictions in which we conduct business, ETP’s activities are conducted through its subsidiary operating partnerships, ETC OLP, a Texas limited partnership engaged in midstream and transportation and storage natural gas operations, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations (collectively the “Operating Partnerships”). LE GP, LLC, ETP LLC, ETP GP, ETP, the Operating Partnerships and their subsidiaries are collectively referred to in this report as “we”, “us”, “our”, “ETP LLC” or “the Company.”

Our midstream operations focus on gathering, compression, treating, blending, processing and marketing of natural gas, currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas.

Our transportation and storage operations focus on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through the Oasis Pipeline, the East Texas Pipeline, the Fort Worth Basin Pipeline, the natural gas pipeline and storage assets that are referred to as the ET Fuel System, and the natural gas pipeline and storage assets of the HPL System.

Our propane operations consist of HOLP and Titan which collectively sell propane and propane-related products to more than 1,000,000 active residential, commercial, industrial, and agricultural customers from 442 customer locations in 41 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership, a Canadian partnership in which we own a 60% interest, engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

2.	SIGNIFICANT ACQUISITIONS:

On June 1, 2006, we acquired all the propane operations of Titan Energy Partners, LP and Titan Energy, GP LLC (collectively “Titan”) for cash of approximately $548,000, after working capital adjustments and net of cash acquired, and liabilities assumed of approximately $46,000. This acquisition was initially financed by borrowings under the ETP Revolving Credit Facility. Titan’s propane assets primarily consist of retail propane operations in 33 states conducted from 146 district locations located in high growth areas of the U.S. The addition of the Titan assets expanded our retail propane operations into six additional states and several new operating territories in which we did not previously have operations. This expansion will further reduce the impact on the propane operations from weather patterns in any one area of the U.S., while continuing our focus on conducting the retail propane operations in attractive high-growth areas. We accounted for the Titan acquisition as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141. The purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition based on the preliminary results of an independent appraisal. We expect to complete the purchase allocation during our first or second quarter of fiscal year 2007 upon the completion of the independent appraisal.

On November 10, 2005, we acquired from American Electric Power Corporation (AEP) the 2% limited partnership interests we did not previously own in the Houston Pipeline System (“HPL”) for $16,560 in cash. The purchase price was allocated to property, plant and equipment and the minority interest liability associated with the 2% limited partner interests was eliminated. As a result, HPL became a wholly-owned subsidiary of ETC OLP. We also reached a settlement agreement with AEP in November 2005 related to certain inventory and working capital matters associated with the initial 98% HPL acquisition in our fiscal year 2005. The terms of the agreement were not material in relation to our financial position.

In November 2005, we purchased the remaining 50% equity interests in South Texas Gathering for $675. As a result, South Texas Gathering became a wholly-owned subsidiary of ETC OLP.

During the fiscal year ended August 31, 2006, HOLP and Titan collectively acquired substantially all of the assets of eight propane businesses. The aggregate purchase price for these acquisitions totaled $28,902 which included $20,572 of cash paid, net of cash acquired, 99,955 ETP Common Units issued valued at $4,000 and liabilities assumed of $4,327. The cash paid for acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for these fiscal year 2006 acquisitions:


	Titan			Midstream and Transportation and Storage Acquisitions			Propane-related Acquisitions (Aggregated)
Cash and equivalents	$	24,458		$	—		$	3
Accounts receivable		20,304			396			1,702
Inventory		11,417			20			795
Prepaid and other current assets		2,055			4			83
Investments in unconsolidated affiliate		—			(50	)		—
Price risk management assets		720			—			—
Property, plant, and equipment		202,598			308			19,276
Intangibles and other assets		74,532			—			5,342
Goodwill		278,149			—			1,701
Other long-term assets		5,055			—			—

Total assets acquired		619,288			678			28,902

Accounts payable		(18,337	)		(211	)		—
Accrued expenses		(14,992	)		(10	)		(1,748	)
Customer advances and deposits		(11,356	)		—			—
Current maturities of long term debt		(964	)		—			—
Long-term debt		(692	)		—			(2,579	)
Minority interest		—			16,667			—

Total liabilities assumed		(46,341	)		16,446			(4,327	)

Net assets acquired	$	572,947		$	17,124		$	24,575

We recorded the following intangible assets in conjunction with these acquisitions:


Customer lists (3-15 years)	$	37,333
Non-compete agreements (5 to 10 years)		2,315
Software		2,200

Total amortized intangible assets		41,848

Trademarks and trade names		35,395
Goodwill		279,850
Other assets		2,631

Total intangible assets and goodwill acquired	$	359,724

We obtained the final independent valuation for the fiscal year 2005 HPL acquisition and made the final allocations of the purchase price to the acquired assets during our fiscal year 2006. The final adjustments, which did not have a material impact on our financial position, resulted in a reduction of $45,820 to the amount allocated to pad gas and an increase of an equal amount to acquired depreciable assets.

3.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Use of Estimates

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the assets and liabilities for the year ended August 31, 2006 represent the actual results in all material respects.

Cash and Cash Equivalents

Marketable Securities

Marketable securities we own are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at fair value.

Accounts Receivable

ETC OLP deals with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master set off agreement). Management reviews midstream and transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debt in ETC OLP’s accounts receivable was not significant at August 31, 2006; therefore, an allowance for doubtful accounts for the midstream and transportation and storage operations was not deemed necessary.

ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheet.

HOLP and Titan grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane and Titan’s retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for HOLP’s and Titan’s retail and wholesale propane operations are recorded as amounts are billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane operations is based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers and any specific disputes.

Accounts receivable consisted of the following at August 31, 2006:


Accounts receivable - midstream and transportation and storage	$	570,569
Accounts receivable - propane		108,976
Less - allowance for doubtful accounts		(4,000	)

Total, net	$	675,545

Inventories

Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are valued at the lower of cost or market utilizing weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts and fittings is determined by the first-in, first-out method. At August 31, 2006, inventories consisted of the following:


Natural gas, propane and other NGLs	$	371,430
Appliances, parts and fittings and other		15,710

Total inventories	$	387,140

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheet. Management believes market value approximates cost.

Property, Plant and Equipment

We review long-lived assets for impairment at least annually and whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, the Company reduces the carrying amount of such assets to fair value.

Components and useful lives of property, plant and equipment at August 31, 2006 (excluding assets held for sale) were as follows:


Land and improvements	$	63,383
Buildings and improvements (10 to 30 years)		70,976
Pipelines and equipment (10 to 65 years)		2,212,805
Natural gas storage (40 years)		91,177
Bulk storage, equipment and facilities (3 to 30 years)		108,834
Tanks and other equipment (5 to 30 years)		472,944
Vehicles (5 to 10 years)		120,710
Right of way (20 to 65 years)		112,185
Furniture and fixtures (3 to 10 years)		16,283
Linepack		24,821
Pad Gas		57,327
Other (5 to 10 years)		27,395

		3,378,840
Less - Accumulated depreciation		(274,809	)

		3,104,031
Plus - Construction work-in-process		644,583

Property, plant and equipment, net	$	3,748,614

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate of our revolving credit facility.

Asset Retirement Obligation

We have completed the assessment of SFAS No. 143, and have determined that we are obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2006 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.

We adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”) on August 31, 2006. FIN 47 clarified that the term “conditional asset retirement obligation” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement of the obligation are uncertain. These conditional obligations were not previously addressed by SFAS 143. FIN 47 requires us to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 did not have a material impact on our consolidated financial position.

Goodwill

Goodwill is associated with acquisitions made by our Operating Partnerships. Of the $633,998 balance in goodwill, $303,870 is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”).

The changes in the carrying amount of goodwill for the year ended August 31, 2006 were as follows:


	Total
Balance as of August 31, 2005	$	353,608
Goodwill acquired during the year including final purchase price adjustments		280,390

Balance as of August 31, 2006	$	633,998

Goodwill acquired during the year includes final purchase price adjustments for prior year acquisitions. The final assessment of asset values related to the Titan acquisition is expected to be completed in the first or second quarter of fiscal year 2007 upon the completion of the final independent appraisal. There is no guarantee that the preliminary allocation will not change.

Investment in Affiliates

We own a 49% interest in Ranger Pipeline, L.P. (“Ranger”), which owns a 50% interest in Mountain Creek Joint Venture (“Mountain Creek”). Mountain Creek is located in North Texas and is composed of approximately 15 miles of pipeline. Mountain Creek supplies gas to an electric generation plant and earns the majority of its yearly income between the months of June and October. We account for our investment in Ranger using the equity method of accounting.

We own a 50% ownership interest in Mid-Texas Pipeline Company (“Mid-Texas”) which owns approximately 139 miles of transportation pipeline that connects various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. We do not exercise management control over Mid-Texas, and, therefore, the investment is accounted for using the equity method of accounting.

We also own a 50% interest in a propane joint venture. This investment is accounted for using the equity method of accounting.

Intangibles and Other Assets


	August 31, 2006
	Gross Carrying Amount		Accumulated Amortization
Amortized intangible assets -
Noncompete agreements (5 to 15 years)	$	31,593	$	(13,012	)
Customer lists (3 to 15 years)		87,480		(11,640	)
Financing costs (3 to 15 years)		24,917		(5,004	)
Consulting agreements (2 to 7 years)		132		(122	)
Other (10 years)		2,677		(422	)

Total		146,799		(30,200	)
Unamortized intangible assets -
Trademarks		64,842		—
Other		5,267		—

Total intangibles and other assets	$	216,908	$	(30,200	)

Customer Advances and Deposits

Fair Value of Financial Instruments

The carrying amounts of accounts receivable and accounts payable approximate their fair value. Derivative financial instruments are carried at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at August 31, 2006 was $3,276,969 and $3,316,753 respectively.

Income Taxes

LE GP, LLC is a limited liability company. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual members. Net earnings for financial statement purposes may differ significantly from taxable income reportable to members as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

We are generally 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 year ended August 31, 2006 our non-qualifying income did not, or was not expected to, exceed the statutory limit.

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

Accounting for Derivative Instruments and Hedging 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 and NGLs. We enter into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date. We had net deposits with derivative counterparties of $87,806 as of August 31, 2006, reflected as deposits paid to vendors on our consolidated balance sheet.

Recently Issued 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 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings for that fiscal year. We are currently evaluating the statement and have not determined the impact of such on our consolidated balance sheet.

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

SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The FASB believes the standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our consolidated balance sheet. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

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

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

4.	DEBT OBLIGATIONS:

Our debt obligations consist of the following as of August 31, 2006:


			Maturities
ETP Senior Notes:
2005 5.95% Senior Notes, net of discount of $1,985	$	748,015	One payment of $750,000 due February 1, 2015. Interest is paid semi-annually.

2005 5.65% Senior Notes, net of discount of $358		399,642	One payment of $400,000 due August 1, 2012. Interest is paid semi-annually.

HOLP Senior Secured Notes:
1996 8.55% Senior Secured Notes		60,000	Annual payments of $12,000 due each June 30^th through 2011. Interest is paid semi-annually.

1997 Medium Term Note Program:
7.17% Series A Senior Secured Notes		9,600	Annual payments of $2,400 due each November 19^th through 2009. Interest is paid semi-annually.

7.26% Series B Senior Secured Notes		14,000	Annual payments of $2,000 due each November 19^th through 2012. Interest is paid semi-annually.

6.50% Series C Senior Secured Notes		357	Annual payments of $357 due March 13, 2007. Interest is paid semi-annually.

2000 and 2001 Senior Secured Promissory Notes:
8.47% Series A Senior Secured Notes		3,200	Annual payments of $3,200 due each August 15^th through 2007. Interest is paid quarterly.

8.55% Series B Senior Secured Notes		18,286	Annual payments of $4,571 due each August 15^th through 2010. Interest is paid quarterly.

8.59% Series C Senior Secured Notes		21,250	Annual payments of $5,750 due August 15, 2007, $4,000 due August 15, 2008, and $5,750 due each August 15, 2009 and 2010. Interest is paid quarterly.

8.67% Series D Senior Secured Notes		58,000	Annual payments of $12,450 due August 15, 2008 and 2009, $7,700 due August 15, 2010, $12,450 due August 15, 2011, and $12,950 due August 15, 2012. Interest is paid quarterly.


8.75% Series E Senior Secured Notes		7,000		Annual payments of $1,000 due each August 15, 2009 through 2015. Interest is paid quarterly.

8.87% Series F Senior Secured Notes		40,000		Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly.

7.21% Series G Senior Secured Notes		7,600		Annual payments of $3,800 due each May 15^th through 2008. Interest is paid quarterly.

7.89% Series H Senior Secured Notes		7,273		Annual payments of $727 due each May 15^th through 2016. Interest is paid quarterly.

7.99% Series I Senior Secured Notes		16,000		One payment of $16,000 due May 15, 2013. Interest is paid quarterly.

Revolving Credit Facilities and Term Loans:
ETE Senior Secured Revolving Credit Facility (including Swingline loan option)		466,291		Available through February 8, 2011 – see terms below under “Revolving Credit Facilities”.

ETE Senior Secured Term Loan		150,000		Due February 8, 2012. See terms below under “Revolving Credit Facilities”.

ETP Revolving Credit Facility (including Swingline loan option)		1,162,624		Available through June 2011 – see terms below under “Revolving Credit Facilities”.

ETP $250,000 Revolving Credit Facility		20,000		Paid and retired in October 2006.

HOLP Fourth Amended and Restated Senior Revolving Credit Facility		20,000		Available through June 30, 2011 – see terms below under “Revolving Credit Facilities”.

ETI Senior Secured Credit Facility		70,500		Due April 24, 2007. See terms below under “Revolving Credit Facilities and Term Loans”.

Other Long-Term Debt:
Notes Payable on noncompete agreements with interest imputed at rates averaging 7.56 %at August 31, 2006		14,204		Due in installments through 2014.

Other		2,911		Due in installments through 2024.

		3,316,753
Current maturities of long-term debt		(40,607	)

	$	3,276,146

Registration Statement

Senior Notes due 2036, and received net proceeds of approximately $791,000. ETP used the proceeds to pay borrowings and accrued interest under its Revolving Credit Facility. Interest on the 2017 Senior Notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 Senior Notes is payable semiannually on April 15 and October 15 of each year, beginning April 15, 2007. The notes are unsecured senior obligations and will be fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries.

Registered Exchange Offer

On November 23, 2005 ETP filed a registered exchange offer to exchange newly issued 5.65% Senior Notes due 2012 (the “2012 Notes”) that were registered under the Securities Act of 1933 (the “New Notes”), for a like amount of outstanding 5.65% Senior Notes due 2012, which had not been registered under the Securities Act (the “Old Notes”). On February 23, 2006 ETP commenced the exchange offer which closed on March 31, 2006. All $400,000 of the Old Notes were tendered pursuant to the exchange offer and were replaced with a like amount of New Notes. The sole purpose of the exchange offer was to fulfill our obligations under the registration rights agreement entered into in connection with our sale of the Old Notes on July 29, 2005. The New Notes issued pursuant to the exchange offer have substantially identical terms to the Old Notes.

2005 Senior Notes

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

HOLP Senior Secured Notes

Revolving Credit Facilities and Term Loans

On April 24, 2006, ETI entered into a $40,000 Senior Secured Credit Facility (the “ETI Senior Secured Credit Facility”) which was amended to $70,500 in July 2006. The ETI Senior Secured Credit Facility matures under its terms on April 24, 2007. All of the proceeds of the ETI Senior Secured Credit Facility were used to repurchase Class A limited partner interests of ETI from certain existing holders in two separate tender offers. The ETI Senior Secured Credit Facility is secured by a first priority lien on all of the assets of ETI which consist solely of ETI’s ownership of 50% of the Class B limited partner interests in ETP GP. The ETI Senior Secured Credit Facility bears interest at ETI’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margin is a function of the ETI’s leverage ratio. The weighted average interest rate was 7.51% for the amount outstanding on the ETI Senior Secured Credit Facility. The ETI Senior Secured Credit Facility was assumed by ETE on November 1, 2006 (see Note 11).

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

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

The maximum commitment fee payable on the unused portion of the ETE Revolving Credit Facility is 0.5%. Loans under the ETE Revolving Credit Facility and the Senior Secured Term Loan Facility bear interest at ETE’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of ETE’s leverage ratio. The weighted average interest rate was 6.76% for the amount outstanding on the ETE Senior Secured Revolving Credit Facility and 7.5% on the Senior Secured Term Loan Facility as of August 31, 2006.

The Senior Secured Credit Agreement is secured by a lien on ETE’s assets, including the capital stock and assets of ETP LLC and ETP GP and its ownership of 36.4 million ETP Common Units.

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

On December 13, 2005 ETP entered into the $900,000 ETP Revolving Credit Facility which replaced the existing Revolving Credit Facility. The ETP Revolving Credit Facility was amended on June 29, 2006 (the Amended and Restated Credit Agreement) allowing for borrowings up to $1,300,000, expandable to $1,500,000. The Amended and Restated Credit Agreement is available through June 29, 2011 unless we elect the two successive options (and the banks agree) to extend the maturity date for a period of 364 days each. Amounts borrowed under the Amended and Restated Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Amended and Restated Credit Agreement has a Swingline loan option with a maximum borrowing of $75,000 at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating and the maximum fee is 0.175%. As of August 31, 2006 there was a balance of $1,145,000 in revolving credit loans, $17,624 in Swingline loans and $14,368 in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2006, was 6.04%. The total amount available under the Amended and Restated Revolving Credit Agreement as of August 31, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $123,008. The Amended and Restated Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP and Titan and its wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On September 25, 2006 we exercised the accordion feature and expanded the total amount of the facility to $1,500,000.

On May 31, 2006, ETP entered into a $250,000 Revolving Credit Facility, which matures under its terms on December 1, 2006. Amounts borrowed under this facility bear interest at a rate based on either a Eurodollar rate or a base rate. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The $250,000 Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP, Titan and all of their direct and indirect wholly-owned subsidiaries of ETC OLP. The $250,000 Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On July 3, 2006, ETP reduced its borrowing capacity on the Revolving Credit Facility to $200,000. All terms, and maturity date, as mentioned above remain unchanged. There was $20,000 outstanding on this facility as of August 31, 2006. The weighted average interest rate on the total amount outstanding at August 31, 2006 was 5.988%. This facility was paid and retired on October 18, 2006.

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

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 Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, 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. We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of August 31, 2006.

Future maturities of long-term debt for each of the next five fiscal years and thereafter are as follows:


2007	$	40,607
2008		46,954
2009		43,974
2010		41,470
2011		1,681,660
Thereafter		1,462,088

	$	3,316,753

5.	MEMBERS’ EQUITY:

The LE GP, LLC membership agreement contains specific provisions for the allocation of net earnings and losses to members for purposes of maintaining the partner capital accounts. The Board of the Company may distribute to the Members funds of the Company which the Board reasonably determines are not needed for the payment of existing or foreseeable company obligations and expenditures.

6.	INCOME TAXES:


Property, plant and equipment	$	206,460
Other, net		2,046

Total deferred tax liability	$	208,506

7.	COMMITMENTS AND CONTINGENCIES:

Commitments

We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Fiscal year future minimum lease commitments for such leases are $8,809 in 2007; $8,889 in 2008; $8,057 in 2009; $7,232 in 2010, $6,557 in 2011 and $9,634 thereafter.

Contingencies

Litigation

of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.

As of August 31, 2006 an accrual of $32,148 was recorded as accrued and other current liabilities on our consolidated balance sheet for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental

We also assumed certain environmental remediation matters related to eleven sites in connection with our acquisition of HPL.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our August 31, 2006 consolidated balance sheet. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition.

As of August 31, 2006, an accrual on an undiscounted basis of $4,387 was recorded in our consolidated balance sheet as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors. A receivable of $388 was recorded in our consolidated balance sheet as of August 31, 2006 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $21,343 during the period between the remainder of calendar year 2006 to 2008. 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 expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

8.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

Non-trading Activities

In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that under SFAS 133 qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. In connection with the HPL acquisition, we acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchase and sale contracts, and therefore, are marked to market in addition to the financial options that offset them. The Black-Scholes valuation model was used to estimate the value of these embedded options.

Trading Activities

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


	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	33,711,140		2006-2009	$	(6,247	)
Swing Swaps IFERC	Gas	(37,220,448	)	2006-2008		2,618
Fixed Swaps/Futures	Gas	3,607,500		2006-2007		(170	)
Forward Physical Contracts	Gas	(7,986,000	)	2006-2008		(21,653	)
Options	Gas	(1,046,000	)	2006-2008		21,653
Forwards/Swaps – in Gallons	Propane	24,066,000		2006-2007		199
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(2,572,500	)	2006-2008		21,995
Swing Swaps IFERC	Gas	—		2006		(31	)
Forward Physical Contracts	Gas	(455,000	)	2006		(68	)

Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,585,000	)	2006-2007		(2,987	)
Fixed Swaps/Futures	Gas	(37,872,500	)	2006-2007		2,043

however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance our positions. To the extent open commodity positions exist in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

Interest Rate Risk

We entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006. We elected to not apply hedge accounting to these financial instruments. The fair value of $629 as of August 31, 2006 related to these treasury locks and interest rate swaps was recorded as a component of price risk management assets in the consolidated balance sheet. In connection with the senior notes issuance described in Note 11, we settled these financial instruments.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125,000. The fair value of this swap as of August 31, 2006 was $519 and recorded as a component of price risk management asset on our consolidated balance sheet. We elected to not apply hedge accounting to these financial instruments.

Credit Risk

9.	RELATED PARTY TRANSACTIONS:

Our natural gas midstream and transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd. Energy Transfer Group, LLC is the General Partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. We did not acquire the ETG Entities in conjunction with the January 2004 Energy Transfer Transactions. Our Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of ETP’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of ETP, no less favorable than those available from other providers of compression services. During fiscal year 2006 we made payments totaling $2,900 to the ETG Entities for compression services provided to and utilized in our natural gas midstream and transportation and storage operations. As of August 31, 2006 accounts payable to ETG related to compressor leases were not material.

On April 28, 2006 ETP entered into a shared services agreement with ETI. Under the terms of the shared services agreement, ETI will reimburse ETP at cost for information technology services, and will pay ETP $36

per year for various other general and administrative services. On the first anniversary of the agreement, ETP will review the charges, costs and expenses actually incurred in providing services in order to determine the fee for ensuing periods. Fees recognized since the inception of this agreement were nominal.

As of August 31, 2006, we had advances due from the propane joint venture of $3,775 which are included in advances to and investments in affiliates on our consolidated balance sheet.

In November 2005, we purchased the remaining 50% equity interest in South Texas Gas Gathering for $675 from an entity that includes one of the General Partner’s directors.

10.

SUPPLEMENTAL INFORMATION:

Following is the balance sheet of the Company, which is included to provide additional information with respect to LE GP, LLC’s financial position on a stand-alone basis as of August 31, 2006:


ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	81
Accounts receivable from related companies		2

Total current assets		83

ADVANCES TO AND INVESTMENT IN AFFILIATES		44

Total assets	$	127

LIABILITIES AND MEMBERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable to related companies		58

MEMBERS’ EQUITY		69

Total liabilities and members’ equity	$	127

11.

SUBSEQUENT EVENTS:

On September 15, 2006, ETP announced that it had entered into agreements with GE Energy Financial Services and Southern Union Company to acquire the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. The agreements provide for a series of transactions in which ETP will acquire all of the member interests in CCE Holdings, LLC (“CCEH”) owned by GE Energy Financial Services and certain other investors. The member interests acquired will represent a 50% ownership in CCEH, which was formed in 2004 to purchase CrossCountry Energy. In the second transaction, CCEH will redeem ETP’s 50% ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”), following which Southern Union Company will own all of the member interests of CCEH. On November 1, 2006 ETP acquired the member interests in CCEH from GE and certain other investors for $1,000,000 and expects to complete the remaining series of transactions in the second quarter of fiscal year 2007. Upon closing, ETP expects the transaction to be immediately accretive to ETP’s Common Unitholders. ETP financed the purchase price with the issuance of approximately 26.1 million ETP Class G Units issued to ETE simultaneous with the closing on November 1, 2006.

On November 1, 2006, ETP issued approximately 26.1 million ETP Class G Units to ETE for aggregate proceeds of $1,200,000 in order to fund a portion of the Transwestern Pipeline acquisition and to repay the indebtedness incurred in connection with the Titan acquisition, as discussed above. The ETP Class G Units, a newly created class of its Limited Partner interests, were issued to ETE at a price of $46.00 per unit, and was based upon a negotiated discount from the closing price of ETP’s Common Units on October 31, 2006. The ETP Class G Units were issued to ETE pursuant to a customary agreement, and registration rights have been granted to ETE.

On November 1, 2006, ETE entered into a First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006 which provided for an additional six year $1,300,000 Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. ETE used the proceeds of the loan to acquire the Class G Units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.

In a separate but related transaction, ETE acquired from ETI, the remaining 50% Class B limited partner interests in ETP GP, which resulted in ETE now owning 100% of the IDRs of ETP. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units and the assumption by ETE of approximately $70,500 of ETI’s indebtedness. The Class C Units have essentially the same voting rights and rights to distributions as the Common Units and Class B Units. The Class C Units are convertible into Common Units upon approval by the ETE Common Unitholders. The Partnership plans to file the required proxy as soon as practicable upon the completion of one year as a public company in February 2007.

12.

SUBSEQUENT PRIVATE PLACEMENT OF ETE UNITS

On November 28, 2006, ETE sold 7,789,133 of ETE 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 $213,500 before expenses. ETE granted registration rights to the investors. ETE plans to use the proceeds to repay indebtedness under its credit facility.