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Filed pursuant to Rule 424(b)(3)
Registration No. 333-146300
PROSPECTUS SUPPLEMENT
Dated November 7, 2007
(to Prospectus Dated October 23, 2007)
 
7,336,588 COMMON UNITS
Representing Limited Partner Interests
 
 
Energy Transfer Equity, L.P.
 
 
 
 
The selling unitholders identified in this prospectus supplement are selling 7,336,588 common units representing limited partner interests in Energy Transfer Equity, L.P. We will not receive any proceeds from the sale of our common units by the selling unitholders in this offering.
 
 
 
 
Energy Transfer Equity, L.P.’s common units are listed on the New York Stock Exchange under the symbol “ETE.” On November 7, 2007, the last reported sales price of our common units on the New York Stock Exchange was $31.70 per common unit.
 
 
 
 
Investing in Energy Transfer Equity, L.P.’s common units involves risks. See “Risk Factors” beginning on page S-14 of this prospectus supplement and beginning on page 4 of the accompanying base prospectus.
 
 
 
 
PRICE $31.70 PER COMMON UNIT
 
 
 
 
                         
          Underwriting
    Proceeds to
 
    Price to
    Discounts and
    Selling
 
    Public     Commissions     Unitholders  
 
Per Common Unit
  $ 31.70     $ 1.268     $ 30.432  
Total
  $ 232,569,840     $ 9,302,794     $ 223,267,046  
 
The selling unitholders have granted the underwriters the right to purchase up to an additional 1,100,489 common units to cover over-allotments, if any.
 
The Securities and Exchange Commission and state securities regulators have not approved or disapproved of these securities, or determined if this prospectus supplement or the accompanying base prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
The underwriters expect to deliver the common units on or about November 13, 2007.
 
 
 
 
Joint Book-Running Managers
 
MORGAN STANLEY  
            CITI  
  UBS INVESTMENT BANK  
  CREDIT SUISSE
November 7, 2007


 

 
TABLES OF CONTENTS
 
         
Prospectus Supplement
  Page
 
  S-1
  S-11
  S-14
  S-44
  S-44
  S-45
  S-46
  S-83
  S-86
  S-87
  S-89
  S-92
  S-92
  S-92
  S-93
  S-94
 
         
Base Prospectus
  Page
 
About this Prospectus
  1
Energy Transfer Equity, L.P. 
  1
Energy Transfer Partners, L.P. 
  1
Cautionary Statement Concerning Forward-Looking Statements
  1
Risk Factors
  4
Use of Proceeds
  34
Description of Our Common Units
  35
Our Cash Distribution Policy
  39
ETP’s Cash Distribution Policy
  42
Material Provisions of Our Partnership Agreement
  46
Material Provisions of ETP’s Partnership Agreement
  57
Material Tax Consequences
  63
Selling Unitholders
  77
Plan of Distribution
  82
Legal Matters
  83
Experts
  83
Where You Can Find More Information
  83
Incorporation of Certain Documents by Reference
  84
 
 
This document is in two parts. The first part is this prospectus supplement, which describes the terms of this common unit offering. The second part is the accompanying base prospectus, which gives more general information, some of which may not apply to this common unit offering. If the information about the offering varies between this prospectus supplement and the accompanying base prospectus, you should rely on the information in this prospectus supplement.
 
You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying base prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying base prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.


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PROSPECTUS SUPPLEMENT SUMMARY
 
This summary highlights information contained elsewhere in this prospectus supplement and the accompanying base prospectus. It does not contain all of the information you should consider before making an investment decision. You should read the entire prospectus supplement, the accompanying base prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. See “Risk Factors” on page S-14 of this prospectus supplement and beginning on page 4 of the accompanying base prospectus for more information about important factors that you should consider before buying common units in this offering. Unless we indicate otherwise, the information we present in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option.
 
As used in this prospectus supplement and the accompanying base prospectus, unless we indicate otherwise, the terms (i) “our,” “we,” “us,” “ETE” and similar terms refer to Energy Transfer Equity, L.P. and its consolidated subsidiaries, (ii) the “Parent Company” refers to Energy Transfer Equity, L.P. on a stand-alone basis, (iii) “ETP” refers to Energy Transfer Partners, L.P., (iv) “ETP GP” refers to Energy Transfer Partners G.P., L.P., (v) “ETP LLC” refers to Energy Transfer Partners, L.L.C. and (vi) the “Operating Partnerships” refers to ETP’s wholly-owned subsidiary operating partnerships, collectively.
 
Energy Transfer Equity, L.P.
 
We are a publicly traded Delaware limited partnership that currently owns three types of equity interests in ETP: (i) the 2% general partnership interest, (ii) 100% of the incentive distribution rights and (iii) approximately 62.5 million common units. ETP is a publicly traded limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, interstate transportation pipelines, natural gas treating and processing assets located in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, and three natural gas storage facilities located in Texas. These assets include approximately 14,000 miles of intrastate pipeline in service, with an additional 500 miles of intrastate pipeline under construction, and 2,400 miles of interstate pipelines. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country. As of November 7, 2007, ETP had an equity market capitalization of approximately $7.2 billion, making it one of the three largest publicly traded master limited partnerships in equity market capitalization. We do not separately conduct any business other than our ownership of interests in ETP.
 
Our Interests in ETP
 
ETE’s aggregate partnership interests in ETP consist of the following:
 
  •  the 2% general partner interest in ETP, which ETE holds through its ownership interests in ETP GP;
 
  •  100% of the outstanding incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP; and
 
  •  approximately 62.5 million common units of ETP, all of which are held directly by ETE.
 
The incentive distribution rights of ETP entitle ETE, as the indirect holder of those rights, to receive the following percentages of cash distributed by ETP as the following target cash distribution levels are reached:
 
  •  13.0% of all incremental cash distributed in a quarter after $0.275 has been distributed in respect of each common unit of ETP for that quarter;
 
  •  23.0% of all incremental cash distributed in a quarter after $0.3175 has been distributed in respect of each common unit of ETP for that quarter; and
 
  •  the maximum sharing level of 48.0% of all incremental cash distributed in a quarter after $0.4125 has been distributed in respect of each common unit of ETP for that quarter.
 
ETP has increased its quarterly distribution on its common units for 15 consecutive quarters. On September 25, 2007, ETP increased the quarterly distribution to $0.825 per unit per quarter for the fiscal quarter ended August 31,


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2007 (or $3.30 per unit on an annualized basis). As ETP has increased the quarterly cash distributions paid on its units, ETE has received increasing payouts on its interests in ETP. These increased cash distributions by ETP have caused the target cash distribution levels described above to be met, thereby increasing the amounts paid by ETP to ETP GP as the owner of ETP’s incentive distribution rights. As a consequence, ETE’s cash distributions from ETP that are based on ETE’s indirect ownership of the incentive distribution rights have increased more rapidly than those based on ETE’s ownership of the general partner interest in ETP and the ETP common units owned by ETE. Future growth in the distributions that ETE receives from ETP will not result from an increase in the sharing level associated with the incentive distribution rights as ETE’s incentive distribution rights currently participate at the maximum sharing level described above.
 
The aggregate amount of ETP’s cash distributions to us will vary depending on several factors, including ETP’s total outstanding partnership interests on the record date for the distribution, the aggregate cash distributions made by ETP and the amount of ETP’s partnership interests ETE owns. If ETP increases distributions to its unitholders, including ETE, ETE expects to increase distributions to its unitholders, although the timing and amount of such increased distributions, if any, will not necessarily be comparable to the timing and amount of the increase in distributions made by ETP. In addition, the level of distributions ETE receives may be affected by the various risks associated with an investment in ETE and the underlying business of ETP. See “Risk Factors” beginning on page S-14.
 
ETE’s primary cash requirements are for general and administrative expenses, debt service and distributions to its partners. ETE’s assets and liabilities are not available to satisfy the debts and other obligations of ETP or its subsidiaries.
 
ETP’s Business
 
Midstream Operations
 
ETP owns and operates approximately 6,260 miles of in-service natural gas gathering pipelines, three natural gas processing plants, five natural gas treating facilities, and ten natural gas conditioning facilities. ETP’s midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas, and ETP’s operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas, the Bossier Sands in east Texas, and the Uinta and Piceance Basins in Utah and Colorado.
 
ETP’s midstream segment accounted for approximately 15% of its total consolidated operating income for the year ended August 31, 2007. ETP’s midstream segment results are derived primarily from margins it realizes for natural gas volumes that are gathered, transported, purchased and sold through its pipeline systems, processed at its processing and treating facilities, and the volumes of natural gas liquids, or NGLs, processed at its facilities. ETP also markets natural gas on its 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 its customers. In addition, ETP generates income from limited trading activities, principally from the use of derivatives, in accordance with its commodity risk management policy.
 
ETP’s midstream segment consists of the following operations and assets:
 
  •  The Southeast Texas System, a 4,300-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. The system includes the La Grange processing plant, five treating facilities and three conditioning facilities. This system is connected to the Katy Hub through the 168-mile East Texas pipeline and is also connected to the Oasis pipeline, as well as two power plants.
 
The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through our system to produce residue gas and NGLs. The plant has a processing capacity of approximately 240 MMcf/d. Our five treating facilities have an aggregate capacity of 700 MMcf/d. These treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality


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specifications. Our three conditioning facilities have an aggregate capacity of 450 MMcf/d. These conditioning facilities remove heavy hydrocarbons from the gas gathered into our systems so the gas can be redelivered and meet downstream pipeline hydrocarbon dew point specifications.
 
  •  The North Texas System, a 160-mile integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett Shale trend. The system includes our Godley plant, as discussed below.
 
The Godley plant was built in two phases to process rich natural gas produced from the Barnett Shale and is connected with the North Texas System and the ET Fuel System. The facility consists of a cryogenic processing plant with processing capacity of approximately 300 MMcf/d. Construction is in progress to increase the aggregate processing capacity to approximately 500 MMcf/d. Construction is scheduled to be completed in the third calendar quarter of 2008.
 
  •  The Canyon Gathering System consists of approximately 1,800 miles of gathering pipeline ranging in diameters from two inches to 16 inches in the Piceance-Uinta Basin of Colorado and Utah and six conditioning plants with an aggregated processing capacity of 90 MMcf/d. The system currently gathers approximately 130,000 MMBtu/d from 1,400 wells and is connected to five major pipeline systems.
 
  •  Interests in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, and the Chalkley Transmission System. On a combined basis, these assets have a capacity of approximately 550 MMcf/d.
 
  •  Marketing operations through ETP’s producer services business, in which ETP markets the natural gas that flows through its pipeline systems, referred to as on-system gas, and attract other customers by marketing volumes of natural gas that do not move through its pipeline systems, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells the natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
 
Substantially all of ETP’s on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or our intrastate transportation pipelines. For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that do not have marketing operations. ETP develops relationships with natural gas producers to facilitate the purchase of their production on a long-term basis.
 
Intrastate Transportation and Storage Operations
 
ETP owns and operates approximately 7,500 miles of intrastate natural gas transportation pipelines, three natural gas storage facilities and six natural gas treating facilities. ETP owns the largest intrastate pipeline system in the United States with interconnects to major consumption areas throughout the United States. ETP’s intrastate transportation and storage segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through its Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, and natural gas pipeline and storage assets that are referred to as the HPL System, which are described below.
 
ETP’s intrastate transportation and storage operations accounted for approximately 59% of its total consolidated operating income for the year ended August 31, 2007. The results from ETP’s intrastate transportation and storage segment are primarily derived from the fees it charges to transport natural gas on its pipelines, including a fuel retention component. ETP also generates revenues and margins 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, ETP purchases natural gas from either the market (including purchases from its midstream segment’s producer services) or from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers based on an index price.
 
ETP also utilizes its Bammel storage facility to engage in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. ETP generally purchases physical natural gas and then sells financial contracts at a price sufficient to cover its carrying costs and provide for a gross profit margin.


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ETP’s intrastate transportation and storage segment consists of the following:
 
  •  The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,200 miles of intrastate natural gas pipeline and related natural gas storage facilities. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in east Texas, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 3.3 Bcf/d of natural gas and total working storage capacity of 12.4 Bcf of natural gas.
 
The ET Fuel System also operates its 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 its Bryson natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Included in the ET Fuel System is a significant portion of ETP’s recently completed Cleburne to Carthage pipeline that connects its North Texas pipeline, a part of its ET Fuel System, its pipelines in the Barnett Shale region, and its Bethel storage facility to its Texoma pipeline in East Texas.
 
In addition, the ET Fuel System is connected with ETP’s Godley plant. This connection gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
 
  •  The Oasis pipeline, a 583-mile natural gas pipeline that directly connects the Waha Hub to the Katy Hub. The Oasis pipeline is primarily a 36-inch diameter natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
 
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing ETP’s Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by:
 
  •  providing ETP with the ability to bypass the La Grange processing plant when processing margins are unfavorable;
 
  •  providing access for natural gas on the Southeast Texas System to other third party supply and market points and interconnecting pipelines; and
 
  •  allowing ETP to bypass our treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
 
  •  The HPL System is comprised of approximately 4,400 miles of intrastate natural gas pipeline with an aggregate capacity of 4.4 Bcf/d, six treating facilities with aggregate capacity of 280 MMcf/d, the underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast of Texas, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System also includes 32 miles of the Cleburne to Carthage pipeline from ETP’s Texoma pipeline interconnect to the Carthage Hub. The HPL System is well situated to gather gas in many of the major gas producing areas in Texas and has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contributes to ETP’s overall ability to play an important role in the Texas natural gas markets. The HPL System is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple


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market hubs at Katy, the Houston Ship Channel and Agua Dulce, and its operation of the Bammel storage facility.
 
The Bammel storage facility has a total working gas capacity of approximately 62 Bcf and has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.
 
On October 9, 2007, ETP announced its plan to expand our Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub, or the Carthage Loop, which expansion is expected to add 500 MMcf/d of pipeline capacity from Cleburne to the Carthage Hub. The Carthage Loop is expected to be in service by the third calendar quarter of 2008.
 
  •  The East Texas pipeline is a 168-mile natural gas pipeline that connects three treating facilities, one of which ETP owns, with its Southeast Texas System. This pipeline was the first phase of a multi-phased project that increased service to producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansion had an initial capacity of over 400 MMcf/d which increased to the current capacity of 675 MMcf/d with the addition of the Grimes County Compressor Station. Over 500 MMcf/d of pipeline capacity is contracted under long-term agreements.
 
On October 9, 2007, ETP announced an expansion of our East Texas pipeline, referred to as the Katy expansion, with the installation of 56 miles of 36-inch pipeline and the addition of 20,000 horsepower of compression. The Katy expansion will increase the capacity on the East Texas pipeline from approximately 700 MMcf/d to more than 1.1 Bcf/d and is expected to be in service by the third calendar quarter of 2008.
 
Interstate Transportation Operations
 
ETP’s interstate transportation segment accounted for approximately 12% of its total consolidated operating income for the year ended August 31, 2007. The results from ETP’s interstate transportation segment are primarily derived from the fees earned from natural gas transportation services and operational gas sales. ETP’s interstate transportation operation began in fiscal 2007 with the acquisition of Transwestern Pipeline Company, LLC, or Transwestern.
 
Our interstate transportation segment consists of the following:
 
  •  The Transwestern pipeline, an open-access natural gas interstate pipeline extending approximately 2,400 miles from the gas producing regions of West Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern pipeline has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets like Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the Natural Gas Act, or NGA, and is subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission, or FERC, which regulates our interstate natural gas pipeline interests. The operating results for Transwestern are included in our results on a consolidated basis as of the acquisition date (December 1, 2006).
 
During fiscal year 2007, Transwestern initiated the Phoenix project, consisting of 260 miles of 42-inch and 36-inch pipeline lateral, with a throughput capacity of 500 MMcf/d, connecting the Phoenix area to Transwestern’s existing mainline at Ash Fork, Arizona and approximately 25 miles of 36-inch pipeline looping of Transwestern’s existing San Juan lateral, adding 375 MMcf/d of capacity. Transwestern filed with the FERC for a certificate of public convenience and necessity on September 15, 2006. The final Environmental Impact Statement was issued by FERC on September 21, 2007. A final FERC certificate is


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expected in fall 2007, with construction beginning immediately thereafter. The project is expected to be partially in-service in the third calendar quarter of 2008 and completely in-service in the fourth calendar quarter of 2008.
 
  •  A joint development with Kinder Morgan Energy Partners, L.P. for ETP’s 50% interest in Midcontinent Express Pipeline, or MEP, an approximately 500-mile interstate natural gas pipeline scheduled to be in service during the second calendar quarter of 2009, that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, that transports natural gas to the significant natural gas markets in the northeast portion of the United States.
 
Retail Propane Operations
 
ETP is one of the three largest retail propane marketers in the United States, based on gallons sold. ETP serves more than one million customers from approximately 440 customer service locations in approximately 40 states. ETP’s propane operations extend from coast to coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. ETP’s propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth.
 
ETP’s retail propane operations accounted for approximately 15% of its total consolidated operating income for the year ended August 31, 2007. The retail propane segment is a margin-based business in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which ETP has no control. ETP has generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane, but there is no assurance that it will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, the profitability of ETP’s propane operations will be sensitive to changes in wholesale propane prices.
 
ETP’s propane business is largely seasonal and dependent upon weather conditions in its service areas. Historically, approximately two-thirds of its retail propane volume and substantially all of our propane-related operating income, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segment during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Cash flow from operations is generally greatest during our second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to commercial and industrial customers are much less weather sensitive.
 
A substantial portion of ETP’s propane is used in the heating-sensitive residential and commercial markets causing the temperatures in its areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of its propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use.
 
The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.
 
Business Strategy and Competitive Strengths
 
ETE’s Business Strategy
 
ETE’s current primary business objective is to increase its cash distributions to its unitholders by actively assisting ETP in executing its business strategy by assisting in identifying, evaluating, and pursuing acquisitions and growth opportunities. In general, ETE expects that it will allow ETP the first opportunity to pursue any acquisition or internal growth project that may be presented to ETE which is within the scope of ETP’s operations or business


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strategy. In the future, ETE may also support the growth of ETP through the use of ETE’s capital resources, which could involve loans, capital contributions or other forms of credit support to ETP. This funding could be used for the acquisition by ETP of a business or asset or for an internal growth project. In addition, the availability of this capital could assist ETP in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
 
ETP’s Business Strategy and Strengths
 
ETP’s primary objective is to increase unitholder distributions and the value of its common units. We believe ETP has engaged, and will continue to engage, in a well-balanced plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of its existing assets.
 
ETP intends to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each ETP common unit. We believe that ETP’s pursuit of independent operating and growth strategies for ETP’s natural gas operations and retail propane business, ETP will be best positioned to achieve its objectives.
 
We expect that acquisitions by ETP in its natural gas operations will be the primary focus of ETP’s acquisition strategy going forward, as evidenced by its acquisition of the Transwestern pipeline and Canyon Gathering System, although ETP will also continue to pursue complementary propane acquisitions, as evidenced by its acquisition of Titan Propane in June 2006. We also anticipate that ETP’s natural gas operations will provide internal growth projects of greater scale compared to those available in its propane business, as demonstrated by ETP’s Cleburne to Carthage pipeline, the Phoenix project and other recently announced projects.
 
We believe that ETP is well-positioned to compete in both the natural gas operations and retail propane industries based on the following strengths:
 
  •  ETP’s enhanced access to capital and financial flexibility will allow it to compete more effectively in acquiring assets and expanding its systems. We expect that ETP’s credit facilities will increase its financial flexibility and enhance its access to capital. We believe this will allow ETP to implement its operating strategies in a timely manner and more effectively compete in acquiring additional assets or expanding its existing systems.
 
  •  ETP’s experienced management team has an established reputation as highly-effective, strategic operators within its operating segments. In the past, the management teams of each of its operating segments have been successful in identifying and consummating strategic acquisitions that enhance its businesses. In addition, ETP’s management team has a substantial equity ownership in us and is motivated through performance-based incentive compensation programs of ETP to effectively and efficiently manage ETP’s business operations.
 
Natural Gas Operations Business Strategies
 
Enhance Profitability of Existing Assets.  ETP intends to increase the profitability of its existing asset base by adding new volumes of natural gas under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
 
Engage in Construction and Expansion Opportunities.  ETP intends to leverage its existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.
 
Increase Cash Flow from Fee-Based Businesses.  ETP intends to seek to increase the percentage of its midstream business conducted with third parties under fee-based arrangements in order to reduce its exposure to changes in the prices of natural gas and NGLs.
 
Growth through Acquisitions.  ETP intends to continue to make strategic acquisitions of midstream, transportation and storage assets in our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of ETP’s existing and acquired assets.


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Natural Gas Operations Business Strengths
 
We believe ETP is well positioned to successfully achieve its primary business objectives and execute its business strategies based on the following competitive strengths in its natural gas operations:
 
  •  ETP’s assets provide marketing flexibility through its access to numerous markets and customers.
 
  •  ETP has a significant market presence in each of its operating areas.
 
  •  ETP’s Southeast Texas System has additional capacity, which provides opportunities for higher levels of utilization.
 
  •  ETP’s ability to bypass its La Grange and Godley processing plants reduces its commodity price risk.
 
Propane Business Strategies
 
Pursue Internal Growth Opportunities.  In addition to pursuing expansion through acquisitions, ETP has aggressively focused on high return internal growth opportunities at its existing customer service locations. ETP believes that by concentrating its operations in areas experiencing higher-than-average population growth, it is well positioned to achieve internal growth by adding new customers.
 
Growth through Complementary Acquisitions.  ETP’s position as one of the three largest propane marketers in the United States provides it a solid foundation to continue its acquisition growth strategy through consolidation.
 
Maintain Low-Cost, Decentralized Operations.  ETP focuses on controlling costs, and attributes its low overhead costs primarily to its decentralized structure.
 
Propane Business Strengths
 
We believe ETP is well positioned to successfully achieve its primary business objectives and execute its business strategies based on the following competitive strengths in its propane business:
 
  •  ETP has a geographically diverse retail propane network.
 
  •  ETP has experience in identifying, evaluating and completing acquisitions.
 
  •  ETP’s operations are focused in areas experiencing higher-than-average population growth.
 
Recent Developments
 
Significant Fiscal Year 2007 Achievements
 
Our significant fiscal year 2007 achievements included the following:
 
  •  ETE received distributions from ETP of $175.0 million, $12.7 million and $183.1 million related to its limited partner interests, general partner interests and incentive distribution rights, respectively.
 
  •  On a consolidated basis, we had revenues of approximately $7.0 billion, operating income of approximately $810.0 million and net income of approximately $319.0 million.
 
  •  ETP’s acquisition of the Transwestern pipeline on December 1, 2006.
 
  •  ETP’s execution of an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of MEP.
 
  •  ETP’s completion of the Cleburne to Carthage pipeline.
 
  •  The commencement of construction by ETP of its Southeast Bossier pipeline, approximately 157 miles of predominately 42-inch pipe connecting ETP’s East Texas and Cleburne to Carthage pipelines with the Texoma pipeline (which is a part of ETP’s HPL System) north of Beaumont, Texas, which ETP expects to complete by the second calendar quarter of 2008.
 
  •  The commencement of construction by ETP of its Paris Loop pipeline, a 135 mile pipeline connecting ETP’s existing pipelines in the Barnett Shale region to its Texoma pipeline in Lamar County, Texas, which ETP expects to complete in the second calendar quarter of 2008.
 
  •  ETP’s initiation of the Phoenix project, a planned expansion of the Transwestern pipeline.
 
  •  ETP’s completion of the first phase of the natural gas processing plant in Godley, Texas.


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Other Developments
 
On May 7, 2007, Ray Davis, previously the Co-Chairman and Co-Chief Executive Officer of ETP (see below), and Natural Gas Partners VI, L.P., or NGP and affiliates of each, sold approximately 38.9 million common units of ETE (17.6% of the outstanding common units of ETE) to Enterprise GP Holdings, L.P., or Enterprise or EPE. In addition to the purchase of ETE common units, Enterprise also acquired a 34.9% non-controlling equity interest in the general partner of ETE, LE GP, LLC, or LE GP.
 
Ray C. Davis, previously the Co-Chief Executive Officer and Co-Chairman of ETP, and Co-Chairman of ETE, retired from these positions effective as of August 15, 2007. As a result of Mr. Davis’ retirement, Kelcy L. Warren, formerly Co-Chief Executive Officer and Co-Chairman of ETP and Co-Chairman of ETE, became the sole Chief Executive Officer and Chairman of ETP and sole Chairman of ETE upon the effective date of Mr. Davis’ retirement. Mr. Davis will continue to serve as a director of ETP and ETE.
 
Our Management
 
LE GP, LLC is our general partner. Our 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 president, to appoint a replacement. All of the current directors of our general partner also serve as directors of the general partner of ETP.
 
Our Principal Executive Offices
 
Our principal executive offices are located at 3738 Oak Lawn Avenue, Dallas, Texas 75219. Our telephone number is (214) 981-0700. Our website address is www.energytransfer.com. Information contained on our website, however, does not constitute a part of this prospectus supplement or the accompanying base prospectus.
 
Our Organizational Structure
 
We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. In February 2005, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name to Energy Transfer Equity, L.P. In February 2006, Energy Transfer Equity became a publicly traded Delaware limited partnership and completed our initial public offering of 24,150,000 common units.
 
After giving effect to the sale of common units by the selling unitholders offered hereby:
 
  •  Our general partner will continue to own a 0.3% general partner interest in us.
 
  •  Our public unitholders will own approximately 99.7 million common units representing a 44.6% limited partner interest in us.
 
  •  We will continue to own approximately 62.5 million common units of ETP.
 
  •  We will continue to hold the 2% general partner interest in ETP through our ownership of equity interests in ETP GP.
 
  •  We will continue to hold 100% of the incentive distribution rights in ETP through our ownership of equity interests in ETP GP.
 
The structure chart on the following page reflects our ownership structure upon completion of this offering.


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Energy Transfer Equity’s Ownership and Organizational Chart
 
Ownership of Energy Transfer Equity After This Offering
 
         
Public Common Units
    44.6 %
General Partner Units
    0.3 %
Management & Other Affiliates of Energy Transfer Equity
    55.1 %
       
      100.0 %
       
 
(FLOW CHART)
 
 
(1) LE GP, LLC, as our general partner, has the right, but not the obligation to contribute capital to Energy Transfer Equity, L.P. to maintain its proportionate general partner interest. Our general partner’s general partner interest is represented by 692,065 general partner units.
(2) Class A limited partner interests are entitled to receive cash distributions related to the 2.0% general partner interest owned by Energy Transfer Partners GP, L.P. in Energy Transfer Partners, L.P.
(3) Class B limited partner interests are entitled to receive their pro rata share of cash distributions related to the incentive distribution rights owned by Energy Transfer Partners GP, L.P. in Energy Transfer Partners, L.P.
(4) Includes approximately 1.1 million common units owned by management of Energy Transfer Partners, L.P.


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THE OFFERING
 
Common units offered 7,336,588 common units; 8,437,077 common units if the underwriters exercise their over-allotment option in full.
 
Units outstanding after this offering 222,829,956 common units; 222,829,956 common units if the underwriters exercise their over-allotment option in full.
 
Use of proceeds We will not receive any proceeds from this offering.
 
Cash distributions Under our partnership agreement, we must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. We declared a quarterly cash distribution for our fourth quarter of fiscal 2007 (ending August 31, 2007) of $0.39 per unit per common, or $1.56 on an annualized basis. We paid this cash distribution on October 19, 2007 to unitholders of record at the close of business on October 5, 2007.
 
We plan to change our fiscal year, which currently ends on August 31, to the calendar year. In connection with this change, we expect that we will transition to making quarterly cash distributions on a calendar quarter basis that will be paid within 50 days following the end of each calendar quarter. To facilitate this transition, we will not make a cash distribution for the three month period ending November 30, 2007, but instead will make a cash distribution for the four month period ending December 31, 2007 that would be paid no later than February 19, 2008.
 
Limited call right If at any time our affiliates own more than 90% of our outstanding units, our general partner has the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units. Management and other affiliates of our general partner currently own approximately 55.1% of our common units on a fully diluted basis. The provision of our partnership agreement that grants this limited call right cannot be amended without the approval of the holders of at least 90% of the outstanding units.
 
Limited voting rights Our general partner manages and operates us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its officers or directors. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including units owned by our general partner and its affiliates, voting together as a single class. Management and other affiliates of our general partner currently own approximately 55.1% of our outstanding common units. This ownership level will enable our general partner and these affiliates to prevent our general partner’s involuntary removal.
 
Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the cash distributed with respect to that period. For the basis of this estimate, see “Material Tax Considerations — Ratio of Taxable Income to Distributions.”


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Exchange listing Our common units are listed on the New York Stock Exchange under the symbol “ETE.”
 
Affiliate purchases Certain of our officers, directors and other affiliates may, but are not obligated to, purchase common units in this offering at the price to public set forth on the cover page of this prospectus supplement.
 
Risk factors Investing in the notes involves risks. See “Risk Factors” beginning on page S-14 of this prospectus supplement and on page 4 of the accompanying base prospectus and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the common units.
 
The FERC and the Commodity Futures Trading Commission, or CFTC, are pursuing legal actions against ETP relating to certain natural gas trading and transportation activities, and related third party claims have been filed against ETE and ETP. For a discussion of these matters, see “Risk Factors — Risks Related to Energy Transfer Partners’ Business — “The FERC and CFTC are pursuing legal actions against ETP relating to certain natural gas trading and transportation activities, and related third party claims have been filed against ETE and ETP.”


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SUMMARY HISTORICAL FINANCIAL DATA
 
The following table sets forth summary historical financial data of ETE for the periods and as of the dates indicated. The following summary financial data for each of the years in the three-year period ended August 31, 2007 has been derived from our consolidated financials statements. You should read the following information in conjunction with our historical consolidated financial statements and related notes thereto incorporated by reference in this prospectus supplement and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus supplement. The amounts in the table below, except per unit data, are in thousands.
 
                         
    Year Ended August 31,  
    2007     2006     2005  
 
Statement of Operations Data:
                       
Revenues:
                       
Midstream segment
    2,853,496       4,223,544       3,246,772  
Intrastate transportation and storage segment
    3,915,932       5,013,224       2,608,108  
Interstate transportation segment
    178,663              
Eliminations
    (1,562,199 )     (2,359,256 )     (471,255 )
Retail propane segment
    1,284,867       879,556       709,473  
Other
    121,278       102,028       75,700  
                         
Total revenues
    6,792,037       7,859,096       6,168,798  
Gross margin
    1,713,831       1,290,780       787,283  
Depreciation and amortization
    191,383       129,636       105,751  
Operating income
    809,336       575,540       297,921  
Interest expense
    279,986       150,646       101,061  
Income from continuing operations before income tax expense and minority interest
    563,359       433,907       201,795  
Income tax expense(a)
    11,391       23,015       4,397  
Minority interests in income from continuing operations
    (232,608 )     (303,752 )     (96,946 )
Income from continuing operations
    319,360       107,140       100,452  
Basic income from continuing operations per limited partner unit(b)
    1.56       0.80       0.89  
Diluted income from continuing operations per limited partner unit(b)
    1.55       0.79       0.75  
Cash distribution per unit
    1.46       2.56       2.66  
Balance Sheet Data (at period end):
                       
Current assets
    1,050,578       1,302,736       1,453,730  
Total assets
    8,183,089       5,924,141       4,905,672  
Current liabilities
    932,815       1,020,787       1,244,785  
Long-term debt (less current maturities)
    5,198,676       3,205,646       2,275,965  
Partners’ capital (deficit)
    (47,132 )     45,751       (88,137 )
Other Financial Data:
                       
Cash flow provided by operating activities
    754,497       310,782       38,133  
Cash flow used in investing activities
    (2,158,090 )     (1,244,406 )     (1,131,117 )
Cash flow provided by financing activities
    1,454,739       926,369       1,043,591  
Capital expenditures:
                       
Maintenance
    89,226       51,826       41,054  
Growth
    998,075       677,861       155,405  
Acquisition
    90,695       586,185       1,131,844  
 
 
(a) As a partnership, we are not generally subject to income taxes. However, three of our subsidiaries, Oasis Pipe Line, Heritage Holdings, Heritage Service Corporation and Titan Propane Services, Inc., are corporations subject to income taxes.
(b) See Note 4 to our consolidated financial statements incorporated by reference in this prospectus supplement for a discussion of the computation of earnings per unit.


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RISK FACTORS
 
An investment in our common units involves risk. You should carefully read the risk factors set forth below, the risk factors included under the caption “Risk Factors” beginning on page 4 of the accompanying base prospectus, and those risk factors discussed in our Annual Report on Form 10-K for the year ended August 31, 2007, which is incorporated by reference into this prospectus supplement and the accompanying base prospectus.
 
Risks Inherent in an Investment in Us:
 
Our only assets are our partnership interests, including the incentive distribution rights, in ETP and, therefore, our cash flow is dependent upon the ability of ETP to make distributions in respect of those partnership interests.
 
The amount of cash that ETP can distribute to its partners, including us, each quarter depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:
 
  •  the amount of natural gas transported through ETP’s transportation pipelines and gathering systems;
 
  •  the level of throughput in its processing and treating operations;
 
  •  the fees it charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;
 
  •  the price of natural gas;
 
  •  the relationship between natural gas and NGL prices;
 
  •  the weather in its operating areas;
 
  •  the cost of the propane it buys for resale and the prices it receives for its propane;
 
  •  the level of competition from other midstream companies, interstate pipeline companies, propane companies and other energy providers;
 
  •  the level of its operating costs;
 
  •  prevailing economic conditions; and
 
  •  the level of ETP’s hedging activities.
 
In addition, the actual amount of cash that ETP will have available for distribution will also depend on other factors, such as:
 
  •  the level of capital expenditures it makes;
 
  •  the level of costs related to litigation and regulatory compliance matters;
 
  •  the cost of acquisitions, if any;
 
  •  the levels of any margin calls that result from changes in commodity prices;
 
  •  its debt service requirements;
 
  •  fluctuations in its working capital needs;
 
  •  its ability to make working capital borrowings under its credit facilities to make distributions;
 
  •  its ability to access capital markets;
 
  •  restrictions on distributions contained in its debt agreements; and
 
  •  the amount, if any, of cash reserves established by its general partner in its discretion for the proper conduct of ETP’s business.


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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. See “ — Risks Related to Energy Transfer Partners’ Business” for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.
 
We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.
 
The source of our earnings and cash flow is cash distributions from ETP. Therefore, the amount of distributions we are currently able to make to our unitholders may fluctuate based on the level of distributions ETP makes to its partners. ETP may not be able to continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if ETP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP to us.
 
Our ability to distribute cash received from ETP to our unitholders is limited by a number of factors, including:
 
  •  interest expense and principal payments on our indebtedness;
 
  •  restrictions on distributions contained in any current or future debt agreements;
 
  •  our general and administrative expenses;
 
  •  expenses of our subsidiaries other than ETP, including tax liabilities, if any;
 
  •  capital contributions to maintain our 2% general partner interest in ETP as required by the partnership agreement of ETP upon the issuance of additional partnership securities by ETP; and
 
  •  reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.
 
We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.
 
The general partner is not elected by the unitholders and cannot be removed without its consent.
 
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner.
 
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units. Because management and affiliates of our general partner (including Enterprise GP Holdings L.P.) own approximately 123.2 million common units, representing 55.1% of our outstanding common units, it will be particularly difficult for our general partner to be removed without the consent of such affiliates. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.


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A reduction in ETP’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.
 
Our direct and indirect ownership of 100% of the incentive distribution rights in ETP (50% prior to November 1, 2006), through our ownership of equity interests in Energy Transfer Partners GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which Energy Transfer Partners GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per common unit per quarter would reduce Energy Transfer Partners GP’s percentage of the incremental cash distributions above $0.3175 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our 2% general partner interest in ETP and our ETP common units.
 
Neither we nor ETP will be prohibited from competing with each other.
 
Neither our partnership agreement nor the partnership agreement of ETP prohibits us from owning assets or engaging in businesses that compete directly or indirectly with ETP or prohibit ETP from owning assets or engaging in businesses that compete directly or indirectly with us, except that ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, we may acquire, construct or dispose of any assets in the future without any obligation to offer ETP the opportunity to purchase or construct any of those assets, and ETP may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
 
Our increased consolidated debt level and our debt agreements and those of our subsidiaries may limit our ability to make distributions to unitholders and may limit the distributions we receive from ETP and our future financial and operating flexibility.
 
As of August 31, 2007, we had approximately $5.2 billion of consolidated debt outstanding. Our level of indebtedness affects our operations in several ways, including, among other things:
 
  •  a significant portion of our and ETP’s cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
 
  •  covenants contained in our and ETP’s existing debt arrangements require us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
 
  •  our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
 
  •  we may be at a competitive disadvantage relative to similar companies that have less debt;
 
  •  we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
 
  •  failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of August 31, 2007, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.


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Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
 
In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of August 31, 2007, we had approximately $5.2 billion of consolidated debt, of which approximately $2.7 billion was at fixed interest rates and approximately $2.5 billion was at variable interest rates. We have entered interest rate swaps for a total notional amount of $1.6 billion, resulting in a net amount of $0.9 billion of variable-rate debt at August 31, 2007. We may enter into additional interest rate swap arrangements. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.
 
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
 
The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.
 
The credit and business risk profiles of our general partner or owners of a general partner may be factors in credit evaluations of us as a master limited partnership. This is because our general partner can exercise significant influence over our business activities, including our cash distributions and, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.
 
We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
 
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the common units, without the approval of our unitholders. The issuance of additional common units or other equity securities by us will have the following effects:
 
  •  our unitholders’ current proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each common unit or partnership security may decrease;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding common unit may be diminished; and
 
  •  the market price of our common units may decline.
 
In addition, ETP may sell an unlimited number of limited partner interests without the consent of its unitholders which will dilute existing interests of its unitholders, including us. The issuance of additional common units or other equity securities by ETP will have essentially the same effects as detailed above.
 
The market price of our common units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing unitholders.
 
Sales by any of our existing unitholders of a substantial number of our units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.


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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 Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Mackie McCrea, President of Midstream Operations, and R. C. Mills, President of Propane Operations. Mr. Warren has been integral to the success of ETP’s midstream and transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing his leadership could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
 
ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
 
An increase in interest rates may cause the market price of our units to decline.
 
Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.
 
Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under limited circumstances.
 
As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions in which we do business. In some of the jurisdictions in which we do business, the applicable statutes do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking


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any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  Your right to act with other unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.
 
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 the SEC, 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.
 
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. As a result, treatment of us as an investment company would result in a material reduction in distributions to you, which would materially reduce the value of our common units. For a discussion of the federal income tax implications if we were treated as a corporation in any taxable year, please read “Material Tax Consequences — Partnership Status” in the accompanying base prospectus.
 
If Energy Transfer Partners GP withdraws or is removed as ETP’s general partner, then we would lose control over the management and affairs of Energy Transfer Partners, the risk that we would be deemed an investment company under the Investment Company Act of 1940 would be exacerbated and our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP could be cashed out or converted into ETP common units at an unattractive valuation.
 
Under the terms of ETP’s partnership agreement, ETP GP will be deemed to have withdrawn as general partner if, among other things, it:
 
  •  voluntarily withdraws from the partnership by giving notice to the other partners;
 
  •  transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s partnership agreement;


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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 can be removed as ETP’s general partner if that removal is approved by unitholders holding at least 662/3% of ETP’s outstanding units (including units held by ETP GP and its affiliates).
 
If ETP GP withdraws from being ETP’s general partner in compliance with ETP’s partnership agreement or is removed from being ETP’s general partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor general partner to purchase its general partner interests, incentive distribution rights and limited partner interests in ETP for fair market value. If ETP GP withdraws from being ETP’s general partner in violation of ETP’s partnership agreement or is removed from being ETP’s general partner in circumstances where a court enters a judgment that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s general partner, and the successor general partner does not exercise its option to purchase the general partner interests, incentive distribution rights and limited partner interests held by ETP GP in ETP for fair market value, then the general partner interests and incentive distribution rights held by ETP GP in ETP could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP would lose control over the management and affairs of ETP, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act of 1940. In addition, our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP, to which a significant portion of the value of our common units is currently attributable, could be cashed out or converted into ETP common units at an unattractive valuation.
 
Our partnership agreement restricts the rights of unitholders owning 20% or more of our units.
 
Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
 
Future sales of the ETP common units we own or other limited partner interests in the public market could reduce the market price of our unitholders’ limited partner interests.
 
As of August 31, 2007, we owned approximately 62.5 million common units of ETP. If we were to sell and/or distribute our ETP common units to the holders of our equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of ETP’s outstanding common units and our receipt of distributions.
 
Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to our unitholders.
 
Prior to making any distributions to our unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.
 
In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are


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obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our unitholders and cause the value of our common units to decline.
 
An impairment of goodwill and intangible assets could reduce our earnings.
 
At August 31, 2007, our consolidated balance sheet reflected $748.0 million of goodwill and $211.7 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.
 
Risks Related to Conflicts of Interest
 
Although we control ETP through our ownership of its general partner, ETP’s general partner owes fiduciary duties to ETP and ETP’s unitholders, which may conflict with our interests.
 
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including ETP’s general partner, on the one hand, and ETP and its limited partners, on the other hand. The directors and officers of ETP’s general partner have fiduciary duties to manage ETP in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage ETP in a manner beneficial to ETP and its limited partners. The Board of Directors of ETP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
 
For example, conflicts of interest may arise in the following situations:
 
  •  the allocation of shared overhead expenses to ETP and us;
 
  •  the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand;
 
  •  the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business;
 
  •  the determination whether to make borrowings under ETP’s revolving working capital facility to pay distributions to ETP’s partners; and
 
  •  any decision we make in the future to engage in business activities independent of ETP.
 
The fiduciary duties of our general partner’s officers and directors may conflict with those of ETP’s general partner.
 
Conflicts of interest may arise because of the relationships between ETP’s general partner, ETP and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner’s directors are also directors and officers of ETP’s general partner, and have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and ETP’s unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
 
The risk of competition with affiliates of our general partner has increased.
 
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us.


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Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. On May 7, 2007, Enterprise GP Holdings L.P. acquired a 34.9% non-controlling equity interest in our general partner. Enterprise GP Holdings L.P. and its subsidiaries are a North American midstream energy business. As a result, there is greater risk that competition with affiliates of our general partner could occur, which could adversely impact our results of operations and cash available for distribution.
 
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:
 
  •  Our general partner is allowed to take into account the interests of parties other than us, including ETP and its affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
 
  •  Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
 
  •  Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.
 
  •  Our general partner determines which costs it and its affiliates have incurred are reimbursable by us.
 
  •  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
 
  •  Our general partner controls the enforcement of obligations owed to us by it and its affiliates.
 
  •  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
 
  •  provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the Board of Directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from


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unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
 
In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.
 
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of August 31, 2007, management and other affiliates of our general partner own approximately 55.1% of our common units.
 
We own an interstate pipeline that is subject to rate regulation by the Federal Energy Regulatory Commission and, in the event that 15% or more of our outstanding common units, in the aggregate, are held by persons who are not eligible holders, common units held by persons who are not eligible holders will be subject to the possibility of redemption at the then-current market price.
 
We own an interstate pipeline that is subject to rate regulation of the FERC, and as a result our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are eligible holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s rate base upon which tariffs may be established under FERC rate-making policies applicable to entities that pass-through their taxable income to their owners. Eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented and 15% or more of our outstanding common units are held by persons who are not eligible holders, we will have the right to redeem the units held by persons who are not eligible holders at the then-current market price. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our general partner.
 
ETP may issue additional ETP units, which may increase the risk that ETP will not have sufficient Available Cash to maintain or increase its per unit distribution level.
 
ETP has wide latitude to issue additional units on terms and conditions established by its general partner. The payment of distributions on those additional units may increase the risk that ETP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders.
 
The issuance of additional common units or other equity securities of equal rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in ETP will decrease;
 
  •  the amount of cash available for distribution on each common unit may decrease; and


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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 intrastate transportation and storage operations are, to an extent, dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors beyond ETP’s control and have been volatile.
 
Income from ETP’s midstream and intrastate transportation and storage operations are exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the North Texas System, Southeast Texas System and at ETP’s Houston Pipe Line System, or the HPL System, ETP purchases natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gathers and delivers the natural gas to pipelines where ETP typically resells the natural gas at the index price or gas daily average. Generally, the gross margins ETP realizes under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.
 
For a portion of the natural gas gathered and processed at the North Texas System and Southeast Texas System, ETP enters into percentage-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which ETP agrees to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remits to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sells the volumes it keeps to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s results of operations. Under keep-whole arrangements, ETP generally sells the NGLs produced from its gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, ETP’s revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if ETP is not able to bypass its processing plants and sell the unprocessed natural gas. Under processing fee agreements, we process the gas for a fee. If recoveries are less than those guaranteed the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole with regard to contractual recoveries.
 
In the past, the prices of natural gas and NGLs have been extremely volatile, and ETP expects this volatility to continue. For example, during ETP’s fiscal year ended August 31, 2007, the NYMEX settlement price for the prompt month contract ranged from a high of $8.87 per MMBtu to a low of $4.20 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during ETP’s fiscal year ended August 31, 2007 ranged from a high of approximately $1.15 per gallon to a low of approximately $0.83 per gallon. Natural gas prices are subject to significant fluctuations, and ETP cannot assure you that natural gas prices will remain at the high levels recently experienced.
 
ETP’s Oasis pipeline, East Texas pipeline, ET Fuel System and HPL System receive fees for transporting natural gas for its customers. Although a significant amount of the pipeline capacity of the East Texas pipeline and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of ETP’s transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of


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natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels. ETP’s fuel retention fees are also directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase ETP’s fuel retention fees, and decreases in natural gas prices tend to decrease its fuel retention fees.
 
The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:
 
  •  the impact of weather on the demand for oil and natural gas;
 
  •  the level of domestic oil and natural gas production;
 
  •  the availability of imported oil and natural gas;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the availability of local, intrastate and interstate transportation systems;
 
  •  the price, availability and marketing of competitive fuels;
 
  •  the demand for electricity;
 
  •  the impact of energy conservation efforts; and
 
  •  the extent of governmental regulation and taxation.
 
The use of derivative financial instruments could result in material financial losses by ETP.
 
From time to time, ETP has sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms and by the activities ETP conducts in its trading operations. To the extent that ETP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change in ETP’s favor. In addition, even though monitored by management, ETP’s hedging and trading activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.
 
ETP’s success depends upon its ability to continually contract for new sources of natural gas supply.
 
In order to maintain or increase throughput levels on ETP’s gathering and transportation pipeline systems and asset utilization rates at its treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and it may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting ETP’s ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near ETP’s gathering systems or in areas that provide access to its transportation pipelines or markets to which its systems connect. The primary factors affecting ETP’s ability to attract customers to its transportation pipelines consist of its access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.
 
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


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by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.
 
A substantial portion of ETP’s assets, including its gathering systems and its processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Accordingly, ETP’s cash flows will also decline unless it is able to access new supplies of natural gas by connecting additional production to these systems.
 
ETP’s transportation pipelines are also dependent upon natural gas production in areas served by its pipelines or in areas served by other gathering systems or transportation pipelines that connect with its transportation pipelines. A material decrease in natural gas production in ETP’s areas of operation or in other areas that are connected to ETP’s areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP handles, which would reduce ETP’s revenues and operating income. In addition, ETP’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the natural decline rate in ETP’s currently connected supplies.
 
Transwestern derives a significant portion of its revenue from charges to its customers for reservation of capacity, which charges Transwestern receives regardless of whether these customers actually use the reserved capacity. Transwestern also generates revenue from transportation of natural gas for customers without reserved capacity. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in demand for natural gas transportation on the Transwestern system over the long run. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.
 
The volumes of natural gas ETP transports on its intrastate transportation pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel Hub, the four major natural gas trading hubs served by ETP’s pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those ETP operates.
 
ETP may not be able to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for qualified assets.
 
ETP’s strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage, propane and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance its ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. ETP regularly considers and enters into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that ETP believes will present opportunities to realize synergies and increase its cash flow.
 
Consistent with ETP’s acquisition strategy, management is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. ETP cannot assure you that its current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to ETP.
 
In addition, ETP is experiencing increased competition for the assets it purchases or contemplates purchasing. Increased competition for a limited pool of assets could result in ETP losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit ETP’s ability to fully execute its growth strategy. Inability to execute its growth strategy may materially adversely impact the market price of ETP’s securities.


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If ETP does not make acquisitions on economically acceptable terms, its future growth could be limited.
 
ETP’s results of operations and its ability to grow and to increase distributions to unitholders will depend in part on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit.
 
ETP may be unable to make accretive acquisitions for any of the following reasons, among others:
 
  •  because ETP is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
 
  •  because ETP is unable to raise financing for such acquisitions on economically acceptable terms; or
 
  •  because ETP is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does.
 
Furthermore, even if ETP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP may:
 
  •  fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
 
  •  decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
 
  •  significantly increase its interest expense or financial leverage if ETP incurs additional debt to finance acquisitions;
 
  •  encounter difficulties operating in new geographic areas or new lines of business;
 
  •  incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which ETP is not indemnified or for which the indemnity is inadequate;
 
  •  be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
 
  •  less effectively manage its historical assets, due to the diversion of ETP management’s attention from other business concerns; or
 
  •  incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
 
If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that ETP will consider.
 
If ETP does not continue to construct new pipelines, its future growth could be limited.
 
During the past several years, ETP has constructed several new pipelines, and ETP is currently involved in constructing several new pipelines. ETP’s results of operations and its ability to grow and to increase distributable cash flow per unit will depend, in part, on its ability to construct pipelines that are accretive to ETP’s distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
 
  •  ETP is unable to identify pipeline construction opportunities with favorable projected financial returns;
 
  •  ETP is unable to raise financing for its identified pipeline construction opportunities; or
 
  •  ETP is unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.


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Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or results from those projected prior to commencement of construction and other factors.
 
Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks.
 
One of the ways that ETP has grown its business is through the construction of additions to its existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and require the expenditure of significant amounts of capital that ETP will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, ETP’s revenues may not increase immediately following the completion of particular projects. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. Moreover, ETP may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.
 
ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System and North Texas System, and the loss of any of these key producers could adversely affect its financial results.
 
For ETP’s fiscal year ended August 31, 2007, ConocoPhillips Company, Enervest Operating, L.L.C, Encana Oil and Gas (USA) Inc., and Lear Energy, LP supplied ETP with approximately 90% of the Southeast Texas System’s natural gas supply. For ETP’s fiscal year ended August 31, 2007, Encana Oil and Gas (USA), Inc., EOG Resources, Inc., XTO Energy Inc., and Chesapeake Energy Marketing, Inc. supplied ETP with approximately 80% of the North Texas System’s natural gas supply. ETP is not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply ETP, ETP would be adversely affected unless it was able to acquire comparable supplies of natural gas from other producers.
 
ETP depends on key customers to transport natural gas on its East Texas pipeline, ET Fuel System and HPL System.
 
ETP has nine- and ten-year fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on ETP’s pipelines. ETP also has an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which is referred to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. ETP has also entered into two eight-year natural gas storage contracts with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
 
ETP completed its Cleburne to Carthage pipeline in April 2007. The major shippers through the Cleburne to Carthage pipeline expansion to interstate and intrastate markets are XTO Energy, Inc., EOG Resources, Inc., Chesapeake Energy Marketing, Inc., Encana Marketing (USA), Inc., Quicksilver Resources, Inc., and Leor Energy,


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L.P. These shippers have long-term contracts ranging from five to 10 years. The failure of these shippers to fulfill their contractual obligations could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
 
Federal, state or local regulatory measures could adversely affect ETP’s business.
 
ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects ETP’s business and the market for its products. The rates, terms and conditions of some of the transportation and storage services ETP provides on the HPL System, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than our currently approved rates, we may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.
 
ETP’s pipelines and storage facilities are subject to state regulation in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado the states in which ETP operates these types of pipelines. ETP’s intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s business may be adversely affected.
 
ETP’s gathering operations are subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP operates that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s business.
 
ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. The rates ETP charges for storage services are deemed just and reasonable under Texas law unless challenged by complaint. Because the natural gas storage facilities of the ET Fuel System and the HPL System are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRCC-jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.


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The states in which ETP conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.
 
Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws could result in the imposition of administrative, civil and criminal remedies.
 
The FERC and CFTC are pursuing legal actions against ETP relating to certain natural gas trading and transportation activities, and related third party claims have been filed against ETE and ETP.
 
On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties, or the Order and Notice, that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight additional times from December 2003 though August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the NGA. ETP allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by the McGraw — Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha Hub in west Texas on certain dates in December 2005. The FERC’s action against ETP also includes allegations related to ETP’s Oasis pipeline, an intrastate pipeline that transports natural gas between the Waha Hub and the Katy Hub near Houston, Texas. The Oasis pipeline also transports interstate natural gas pursuant to NGPA Section 311 authority, and subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity accounts for approximately 1.0% of ETP’s operating income for its 2007 fiscal year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers (such as utilities and other end-users) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at prices that would be subject to FERC approval. Also on July 26, 2007, the CFTC filed suit in United States District Court for the Northern District of Texas alleging that ETP violated provisions of the Commodity Exchange Act by attempting to manipulate natural gas prices in the Houston Ship Channel. It is alleged that such manipulation was attempted during the period from late September through early December 2005 to allow ETP to benefit financially from ETP’s commodities derivatives positions.
 
In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC ordered ETP to show cause why the allegations against ETP made in the Order and Notice are not true. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. The FERC has taken the position that, once it receives ETP’s response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. In its lawsuit, the CFTC is seeking civil penalties of $130,000 per violation, or three times the profit gained from each violation, and other ancillary relief. The CFTC has not specified the number of alleged violations or the amount of alleged profit related to the matters specified in its complaint. On October 15, 2007, ETP filed a motion to dismiss in the United States District Court for the Northern District of Texas on the basis that the CFTC has not stated a valid cause of action under the Commodity Exchange Act.
 
It is ETP’s position that its trading and transportation activities during the periods at issue complied in all material respects with applicable laws and regulations, and ETP intends to contest these cases, and any related third


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party actions, vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.
 
In addition to the FERC and CFTC legal actions, it is also possible that third parties will assert claims against ETP and ETE for damages related to these matters, which parties could include natural gas producers, royalty owners, taxing authorities, and parties to physical natural gas contracts and financial derivatives based on the Platts Inside FERC Houston Ship Channel index during the periods in question. In this regard, two natural gas producers have initiated legal proceedings against ETP and ETE for claims related to the FERC and CFTC claims. One of the producers has brought suit in Texas state court against ETP and ETE based on contractual and tort claims relating to alleged manipulation of natural gas prices at the Waha Hub in West Texas and the Houston Ship Channel and is seeking unspecified direct, indirect, consequential and punitive damages. The second producer, acting as agent for a group of producers, has brought suit in Texas state court against ETP and ETE based on contract and tort claims relating to a natural gas purchase contract to which ETP and this producer are parties. This producer seeks unspecified damages and requests pre-arbitration discovery of information related to ETP’s activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. The producer also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5.9 million, plus interest and costs. This producer has also filed a complaint at FERC against us and ETP requesting an agency hearing and claiming that we and ETP violated the NGA by failing to make sales for resale at negotiated rates; intentionally engaged in market manipulation; knowingly submitted misleading information to Platts; and caused damages to the producer group in the amount of $5.9 million. This producer has requested refunds and other remedies. In addition, two putative class actions have been filed against us in the United States District Court for the Southern District of Texas. These suits allege that ETP unlawfully manipulated the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act, that ETP has the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, Waha, and Permian hubs, in order to benefit ETP’s natural gas physical and financial trading positions. One of these suits alleges that this unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels between December 29, 2003 and December 31, 2005, causing unspecified damages to plaintiff and all others who purchased and/or sold natural gas futures and options contracts on NYMEX during that period. The other putative class action alleges similar manipulation by us on September 28, 2005 and seeks $500 million in alleged actual damages and other relief. On October 30, 2007, the two putative class actions were found by the court to be related proceedings, and the second putative class action was transferred from the United States District Court for the Southern District of Texas, Galveston, Texas division, to that court’s Houston, Texas division where the first putative class action is filed. We expect that both of these class action lawsuits will be consolidated into one lawsuit.
 
We are expensing the legal fees, consultants’ fees and related expenses relating to the FERC and CFTC legal actions, and related third party actions, in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obligated to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obligated to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.


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Transwestern is subject to laws, regulations and policies governing the rates that it is allowed to charge for its services.
 
Laws, regulations and policies governing interstate natural gas pipeline rates could affect Transwestern’s ability to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. Natural gas companies must charge rates that are deemed to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to the Natural Gas Act, existing rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. Further, other than for rates set under market-based rate authority, rates must be cost-based and the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level. Transwestern filed a general rate case in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file new cost-based rates until October 2011. In addition, shippers (other than shippers who have agreed not to challenge our tariff rates through 2010 pursuant to our recent settlement agreement with these shippers) may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services on a prospective basis. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.
 
The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future refinement or change.
 
The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates of an interstate petroleum products pipeline, Santa Fe Pacific Pipeline, or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification to those rates. The Court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, the FERC issued its first case-specific oil pipeline review of the income tax allowance issues in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income allowance. Further, in the December 2005 order, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through entities pay the maximum marginal tax rate of 35% and that non-corporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the new income tax allowance policy were appealed to the D.C. Circuit. In May 2007, the D.C. Circuit affirmed FERC’s favorable income tax allowance policy. As a result, we remain eligible to include an allowance in the tariff rates we charge for natural gas transportation on our Transwestern interstate pipeline system, subject to our ability to demonstrate compliance with FERC’s policy. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts.


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As FERC has recently approved ETP’s tariff rates specified in a settlement agreement with shippers, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is not subject to challenge by parties to our settlement agreement prior to its expiration.
 
Transwestern is subject to laws, regulations and policies governing terms and conditions of service, which control many aspects of its business.
 
In addition to rate oversight, FERC’s regulatory authority extends to many other aspects of Transwestern’s business and operations, including:
 
  •  operating terms and conditions of service;
 
  •  the types of services Transwestern may offer to its customers;
 
  •  construction of new facilities;
 
  •  acquisition, extension or abandonment of services or facilities;
 
  •  reporting and information posting requirements;
 
  •  accounts and records; and
 
  •  relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
 
Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair Transwestern’s ability to compete for business or increase the cost and burden of operation.
 
Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1.0 million per day for each violation.
 
Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.
 
ETP’s business involves hazardous substances and may be adversely affected by environmental regulation.
 
ETP’s natural gas, as well as its propane operations are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for its operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from ETP’s pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from its operations. Several governmental authorities, such as the U.S. Environmental Protection Agency or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.
 
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. At August 31, 2007, the total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations is approximately $12.3 million, which activities are expected to continue for several years.


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Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For instance, the Texas Commission on Environmental Quality, or TCEQ, recently adopted a rule further restricting the level of nitrogen oxides, or NOx, that may be emitted from stationary gas-fired reciprocating internal combustion engines located in counties comprising the Dallas-Fort Worth eight hour ozone non-attainment area. As a result of the adoption of this rule, by March 1, 2009, ETP must either modify or replace seven owned and 21 leased compressor units currently located in the Dallas-Fort Worth non-attainment area that do not satisfy the TCEQ’s new, more stringent NOx emission limitations. ETP is evaluating its options to comply with this rule and thus the costs to comply currently are not reasonably estimable but such costs ultimately could be material to the operations of ETP. Also, the U.S. Congress is actively considering legislation and more than a dozen states have already taken legal measures to reduce emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere. Moreover, the U.S. Supreme Court recently decided, in Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.
 
Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect ETP’s revenues and cash flow.
 
Users of ETP’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s pipelines. Any reduction in volumes transported in ETP’s pipelines would adversely affect its revenues and cash flow.
 
ETP encounters competition from other midstream, transportation and storage companies and propane companies.
 
ETP experiences competition in all of its markets.  ETP’s principal areas of competition include obtaining natural gas supplies for the Southeast Texas System, North Texas System and HPL System and natural gas transportation customers for its transportation pipeline systems. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems owned by DCP Midstream, LLC. The North Texas System competes with Crosstex North Texas Gathering, LP and Devon Gas Services, LP for gathering and processing. The East Texas pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale region in north Texas. The ET Fuel System and the Oasis pipeline compete with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub. The ET Fuel System competes with other natural gas transportation pipelines serving the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that ETP competes with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P., and Enbridge, Inc. Some of ETP’s competitors may have greater financial resources and access to larger natural gas supplies than it does.
 
The acquisitions of the HPL System and the Transwestern pipeline increased the number of interstate pipelines and natural gas markets to which ETP has access and expanded its principal areas of competition to areas such as southeast Texas and the Texas Gulf Coast. As a result of ETP’s expanded market presence and diversification, ETP faces additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and


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companies that gather, compress, treat, process, transport, store and market natural gas, that may have greater financial resources and access to larger natural gas supplies than ETP does.
 
The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by our pipelines.
 
ETP’s propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:
 
  •  price,
 
  •  reliability and quality of service,
 
  •  responsiveness to customer needs,
 
  •  safety concerns,
 
  •  long-standing customer relationships,
 
  •  the inconvenience of switching tanks and suppliers, and
 
  •  the lack of growth in the industry.
 
The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.
 
Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American Tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
 
ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its unitholders, including to us.
 
The risks of nonpayment and nonperformance by ETP’s customers are a major concern in its business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP is subject to risks of loss resulting from nonpayment or nonperformance by its customers. Any substantial increase in the nonpayment and nonperformance by ETP’s customers could reduce its ability to make distributions to its unitholders, including to us.


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ETP may be unable to bypass the processing plants, which could expose it to the risk of unfavorable processing margins.
 
Because of ETP’s ownership of the Oasis pipeline and ET Fuel System, it can generally elect to bypass the processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the Oasis pipeline and ET Fuel System. In some circumstances, such as when ETP does not have a sufficient amount of lean gas to blend with the volume of rich gas that it receives at the processing plant, ETP may have to process the rich gas. If ETP has to process when processing margins are unfavorable, its results of operations will be adversely affected.
 
ETP may be unable to retain existing customers or secure new customers, which would reduce its revenues and limit its future profitability.
 
The renewal or replacement of existing contracts with ETP’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets ETP serves.
 
For ETP’s fiscal year ended August 31, 2007, approximately 22.4% of its sales of natural gas were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP in the marketing of natural gas, ETP often competes in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on ETP’s profitability.
 
ETP’s storage business depends on neighboring pipelines to transport natural gas.
 
To obtain natural gas, ETP’s storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with ETP. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.
 
ETP’s pipeline integrity program may cause it to incur significant costs and liabilities.
 
ETP’s operations are subject to regulation by the U.S. Department of Transportation, or DOT, under the Pipeline Hazardous Materials Safety Administration, or PHMSA, pursuant to which the PHMSA has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements for its existing transportation assets other than the Transwestern pipeline will result in capital costs of $7.9 million during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $13.1 million during that period. During this same time period, ETP estimates that it will incur pipeline integrity operating and on-going annual maintenance capital costs of $18.7 million with respect to its Transwestern pipeline. Through August 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through August 31, 2007, a total of $13.4 million of capital costs and $11.8 million of operating and


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maintenance costs have been incurred for pipeline integrity testing for transportation assets other than Transwestern. Through August 31, 2007, a total of $2.9 million of capital costs and $0.1 million of operating and maintenance costs have been incurred for pipeline integrity testing for Transwestern. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.
 
Since weather conditions may adversely affect demand for propane, ETP’s financial conditions may be vulnerable to warm winters.
 
Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of ETP’s customers rely heavily on propane as a heating fuel. Typically, ETP sells approximately two-thirds of its retail propane volume during the peak-heating season of October through March. ETP’s results of operations can be adversely affected by warmer winter weather which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect ETP’s operating and financial results, its access to capital and its acquisition activities may be limited. Variations in weather in one or more of the regions where ETP operates can significantly affect the total volume of propane that ETP sells and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including periods of unseasonably cold or hot periods or dry weather conditions which may impact agricultural operations.
 
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect its cash flow and, accordingly, affect the market price of ETP’s common units.
 
Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
 
If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its unitholders, including ETE and, accordingly, adversely affect the market price of ETP’s common units.
 
ETP believes that it maintains adequate insurance coverage, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
 
Terrorist attacks aimed at ETP’s facilities could adversely affect its business, results of operations, cash flows and financial condition.
 
Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist


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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 2007, ETP purchased approximately 23% and 22% of our propane from Targa Liquids and Enterprise, respectively. In addition, we purchased approximately 21% of our propane from M-P Energy Partnership, a Canadian partnership in which we owned through August 31, 2007 a 60% interest. Enterprise is a subsidiary of Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding common units and a 34.9% non-controlling interest in the general partner of ETE, and is therefore considered to be an affiliate of us. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be


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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
 
In addition to reading the following risk factors, you should read “Material Tax Considerations” in this prospectus supplement and “Material Tax Consequences” in the accompanying base prospectus for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us or ETP as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. The value of our investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state income taxes as well. Distributions to unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
If ETP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there


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would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units. Current law may change, causing us or ETP to be treated as a corporation for federal income tax purposes or otherwise subjecting us or ETP to entity-level taxation. For example, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or ETP as an entity, the cash available for distribution to our unitholders would be reduced.
 
The tax treatment of publicly traded partnerships, or an investment in our common units, could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The U.S. federal income tax treatment of unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. You should be aware that the U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS, and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of us or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d) and changing the characterization of certain types of income received from partnerships. It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. For a discussion of the importance of the Qualifying Income Exception and our status as a partnership for federal income tax purposes, please read “Material Tax Considerations” in this prospectus supplement and “Material Tax Consequences — Partnership Status” in the accompanying base prospectus.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, Vinson & Elkins L.L.P. is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. See “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees” in the accompanying base prospectus.
 
If the IRS contests the federal income tax positions we or ETP takes, the market for our common units or ETP common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.
 
The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we or ETP take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we or ETP take. A court may not agree with some or all of our counsel’s conclusions or the positions we or ETP take. Any contest with the IRS may materially and adversely impact the market for our


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common units or ETP’s common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us or ETP, and therefore indirectly by us, as a Unitholder and as the owner of the general partner of ETP, reducing the cash available for distribution to our unitholders.
 
Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income. In such case, unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.
 
Tax gain or loss on disposition of our common units could be more or less than expected.
 
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Because distributions in excess of the Unitholder’s allocable share of our net taxable income decrease the Unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the Unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells units, the unitholders may incur a tax liability in excess of the amount of cash received from the sale. See “Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” in the accompanying base prospectus for a further discussion of the foregoing.
 
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, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
 
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the common units.
 
To maintain the uniformity of the economic and tax characteristics of our common units, we may and have in the past adopted certain depreciation and amortization positions that are inconsistent with existing Treasury Regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our unitholders. For example, prior to our tax termination on May 7, 2007, we did not amortize certain goodwill assets, the value of which was attributed to certain of our outstanding units. A subsequent holder of those units would have been entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we could not then, nor cannot now identify those units once they are traded by the initial holder, we were not giving any subsequent holder of any unit any such amortization deduction. This approach understated deductions available to those unitholders who owned those certain units and may result in those unitholders believing that they have a higher tax basis in their units than is actually the case. This, in turn,


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may result in those unitholders reporting less gain or more loss on a sale of their units than is actually the case. Moreover, as a result of those positions, the IRS may challenge the manner in which we were calculating our unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period under audit as if all unitholders owned such units.
 
Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders.
 
A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a Unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to you. See “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” in the accompanying base prospectus for a further discussion of the effect of the depreciation and amortization positions we adopted.
 
ETP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of ETP. The IRS may challenge this treatment, which could adversely affect the value of ETP’s common units and our common units.
 
When we or ETP issue additional units or engage in certain other transactions, ETP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s unitholders and us. Although ETP may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. ETP’s methodology may be viewed as understating the value of ETP’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP unitholders and us, which may be unfavorable to such ETP unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ETP’s tangible assets and a lesser portion allocated to ETP’s intangible assets. The IRS may challenge ETP’s valuation methods, or our or ETP’s allocation of Section 743(b) adjustment attributable to ETP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’s unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders or the ETP unitholders. It also could affect the amount of gain on the sale of common units by our unitholders or ETP’s unitholders and could have a negative impact on the value of our common units or those of ETP or result in audit adjustments to the tax returns of our or ETP’s unitholders without the benefit of additional deductions.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.
 
Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a twelve month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior twelve month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded. See “Material Tax


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Consequences — Disposition of Common Units — Constructive Termination” in the accompanying base prospectus for a discussion of the consequences of our termination for federal income tax purposes.
 
Based on the information currently available to us, we believe and intend to take the position that the sale of our common units by Ray C. Davis and Natural Gas Partners VI, L.P. to Enterprise GP Holdings, L.P. on May 7, 2007, together with all other common units sold within the prior twelve months, represented a sale or exchange of 50% or more of the total interest in our capital and profits interests and resulted in our termination and immediate reconstitution as a new partnership for federal income tax purposes. Moreover, our termination resulted in a deemed transfer of all of our interests in ETP, causing a termination of ETP’s partnership for federal income tax purposes. These terminations do not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. The closing of our taxable years will result in us and ETP both filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year. Moreover, these terminations will require both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP will be required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the unitholders of ETP (including Heritage Holdings as the holder of our Class E units) and, consequently, to our unitholders. However, elections ETP and ETE will make with respect to the amortization of certain intangible assets should have the effect of reducing the amount of taxable income that would otherwise be allocated to ETE unitholders.
 
We believe that the net effect of our tax termination and the tax termination of ETP will be an allocation for the 2007 calendar year of (i) an increased amount of taxable income as a percentage of the cash distributed to our unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our unitholders who purchased their units on or after the date of our initial public offering in February 2006. We estimate, based on our current distribution levels and various assumptions regarding the gross income and capital expenditures of ETP, that a Unitholder who purchased our units on the date of our initial public offering or a new purchaser of our units would be allocated taxable income of less than 10% of the cash distributed to them for the 2008 calendar year. In the case of a Unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our income or loss being includable in their taxable income for the year of termination.
 
You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
 
In addition to federal income taxes, the unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ETP do business or own property now or in the future, even if they do not live in any of those jurisdictions. unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in us.


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USE OF PROCEEDS
 
We will not receive any proceeds from the sale of our common units by the selling unitholders in this offering.
 
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
 
Our common units are listed on the NYSE under the symbol “ETE.” Our common units began trading on February 2, 2006 at an initial public offering price of $21.00 per unit. The last reported sales price of the common units on the NYSE on November 7, 2007 was $31.70. As of November 5, 2007, we had issued and outstanding 222,829,956 common units, which were held by approximately 23,581 unitholders. The following table sets forth the range of high and low sales prices of the common units, on the NYSE, as well as the amount of cash distributions paid per common unit for the periods indicated.
 
                         
    Price Range     Cash Distribution
 
    High     Low     per Unit  
 
Year ended August 31, 2006:
                       
Second Quarter
  $ 23.29     $ 21.50     $ 0.2000 (1)
Third Quarter
  $ 27.65     $ 21.41     $ 0.2375  
Fourth Quarter
  $ 27.16     $ 24.98     $ 0.3125  
Year ended August 31, 2007:
                       
First Quarter
  $ 29.99     $ 26.04     $ 0.3400  
Second Quarter
  $ 33.70     $ 28.80     $ 0.3560  
Third Quarter
  $ 41.06     $ 33.20     $ 0.3725  
Fourth Quarter
  $ 42.95     $ 29.82     $ 0.3900  
Year ended August 31, 2008:
                       
First Quarter (through November 7, 2007)
  $ 37.35     $ 31.60       (2)
 
 
(1) The initial quarterly cash distribution was prorated based upon the number of days the units were publicly traded during the quarter. The resulting amount of this prorated distribution was $0.0578 per unit for the 26-day period from February 3 to 28, 2006.
(2) We plan to change our fiscal year, which currently ends on August 31, to the calendar year. In connection with this change, we expect that we will transition to making quarterly cash distributions on a calendar quarter basis that will be paid within 50 days following the end of each calendar quarter. To facilitate this transition, we will not make a cash distribution for the three month period ending November 30, 2007, but instead will make a cash distribution for the four month period ending December 31, 2007 that would be paid no later than February 19, 2008.


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SELECTED HISTORICAL FINANCIAL DATA
 
The following table sets forth selected historical financial data of ETE for the periods and as of the dates indicated. The following selected financial data for each of the years in the four-year period ended August 31, 2007 and the eleven months ended August 31, 2003 has been derived from our consolidated financials statements. You should read the following information in conjunction with our historical consolidated financial statements and related notes thereto incorporated by reference in this prospectus supplement and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus supplement. The amounts in the table below, except per unit data, are in thousands.
 
                                         
                            Eleven
 
                            Months
 
                            Ended
 
    Year Ended August 31,     August 31,
 
    2007     2006     2005     2004     2003(a)  
 
Statement of Operations Data:
                                       
Revenues:
                                       
Midstream segment
    2,853,496       4,223,544       3,246,772       1,880,663       899,086  
Intrastate transportation and storage segment
    3,915,932       5,013,224       2,608,108       113,938       41,500  
Interstate transportation segment
    178,663                          
Eliminations
    (1,562,199 )     (2,359,256 )     (471,255 )     (27,798 )     (9,559 )
Retail propane segment
    1,284,867       879,556       709,473       349,344        
Other
    121,278       102,028       75,700       30,810        
                                         
Total revenues
    6,792,037       7,859,096       6,168,798       2,346,957       931,027  
Gross margin
    1,713,831       1,290,780       787,283       365,533       105,589  
Depreciation and amortization
    191,383       129,636       105,751       56,242       11,870  
Operating income
    809,336       575,540       297,921       130,806       55,501  
Interest expense
    279,986       150,646       101,061       41,217       12,453  
Gain on Energy Transfer Transactions
                      395,253        
Income from continuing operations before income tax expense and minority interest
    563,359       433,907       201,795       484,715       44,673  
Income tax expense(b)
    11,391       23,015       4,397       2,792       4,432  
Minority interests in income from continuing operations
    (232,608 )     (303,752 )     (96,946 )     (35,164 )      
Income from continuing operations
    319,360       107,140       100,452       446,759       40,241  
Basic income from continuing operations per limited partner unit(c)
    1.56       0.80       0.89       4.54       0.47  
Diluted income from continuing operations per limited partner unit(c)
    1.55       0.79       0.75       3.35       0.30  
Cash distribution per unit
    1.46       2.56       2.66       1.36       0.03  
Balance Sheet Data (at period end):
                                       
Current assets
    1,050,578       1,302,736       1,453,730       481,868       223,897  
Total assets
    8,183,089       5,924,141       4,905,672       2,865,191       604,140  
Current liabilities
    932,815       1,020,787       1,244,785       404,917       169,967  
Long-term debt (less current maturities)
    5,198,676       3,205,646       2,275,965       1,071,158       196,000  
Partners’ capital (deficit)
    (47,132 )     45,751       (88,137 )     368,325       182,631  
Other Financial Data:
                                       
Cash flow provided by operating activities
    754,497       310,782       38,133       122,098       70,675  
Cash flow used in investing activities
    (2,158,090 )     (1,244,406 )     (1,131,117 )     (731,831 )     (341,258 )
Cash flow provided by financing activities
    1,454,739       926,369       1,043,591       637,513       325,655  
Capital expenditures:
                                       
Maintenance
    89,226       51,826       41,054       22,514       7,691  
Growth
    998,075       677,861       155,405       87,174       4,223  
Acquisition
    90,695       586,185       1,131,844       622,929       340,187  
 
 
(a) On December 27, 2002, ETC OLP purchased the remaining 50% of Oasis Pipe Line. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After such date, Oasis Pipe Line’s results of operations are consolidated with ETC OLP as a wholly-owned subsidiary.
(b) As a partnership, we are not generally subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings, Heritage Service Corporation, and Titan Propane Services, Inc. are corporations subject to income taxes.
(c) See Note 4 to our consolidated financial statements incorporated by reference in this prospectus supplement for a discussion of the computation of earnings per unit.


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto incorporated by reference in this prospectus supplement. 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 “Risk Factors” included elsewhere or incorporated by reference in this prospectus supplement.
 
Overview
 
We were formed in September 2002 and completed our initial public offering of 24,150,000 common units in February 2006.
 
Currently, the Parent Company’s business operations are conducted only through ETP’s Operating Partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC, or ET Interstate, the parent company of Transwestern, and ETC Midcontinent Express Pipeline, LLC, or ETC MEP or MEP, a Delaware limited liability company engaged in interstate transportation of natural gas, and Heritage Operating, L.P, or HOLP, and Titan, both Delaware limited partnerships engaged in retail propane operations.
 
Parent Company — Energy Transfer Equity, L.P.
 
The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Partnerships.
 
The Parent Company’s long-term debt increased significantly during the year ended August 31, 2007 as a result of debt incurred to finance the acquisition of Class G limited partner units of ETP (subsequently converted to common units). The purchase of Class G units increased the Parent Company’s ownership of ETP limited partner interests from approximately 33% to approximately 46%.
 
In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
 
General
 
Our current primary objective is to increase the level of our cash distributions to our partners over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amount of cash that we will have available for distribution will primarily depend on the amount of cash we generate from operations.
 
During the past several years we have been successful in completing several transactions that have been accretive to our unitholders. First and foremost was the completion of the Energy Transfer Transactions, which was the combination of the retail propane operations of Heritage and the midstream and intrastate transportation and storage operations of ETC OLP in January 2004. Subsequent to the combination we have made numerous significant acquisitions in both our natural gas and propane operations, most notably the following:
 
  •  ET Fuel System in June 2004
 
  •  HPL System in January 2005


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  •  Titan Propane in June 2006
 
  •  Transwestern in December 2006
 
Concurrently, we have also made significant investments in internal growth projects which we believe will provide additional cash flow to our unitholders in years to come.
 
Our principal operations are conducted in the following significant segments:
 
  •  Midstream
 
  •  Intrastate transportation and storage
 
  •  Interstate transportation
 
  •  Retail propane
 
Summary of Operating Financial Performance in fiscal 2007
 
The fiscal 2007 year proved to be a challenging year for us. However, despite delays in certain of our major projects and the milder summer months in 2007, particularly in the southern portion of the United States, our management team and assets delivered another strong earnings performance for the year ended August 31, 2007 with $1.7 billion in gross margin and $809.3 million in operating income. In addition to the increased income generated from the Transwestern and Titan acquisitions, we also experienced increased volumes in our natural gas operations and better than expected processing margins throughout the fiscal year. We were also able to withdraw more working natural gas inventories from our Bammel storage facility resulting in increased margins, principally during the three months ended August 31, 2007.
 
ETP’s Operations
 
Our midstream and propane operations are primarily margin-driven businesses, while our transportation and storage operations are primarily fee-driven businesses. Thus, our results are significantly impacted by the margins we realize and the volumes we sell, transport and store, and to a lesser extent, commodity prices. Our fiscal year 2007 results were significantly impacted by our Transwestern acquisition in December 2006 and our Titan acquisition in fiscal year 2006.
 
Despite the warmer than normal winter, our propane operations were able to deliver higher than expected results. Our retail volumes increased as a result of acquisitions during fiscal year 2007 and the Titan and other acquisitions during fiscal year 2006 which offset the decrease in volumes we experienced due to the warmer weather. We also were able to increase our sales prices which improved our gross margins. Additionally, due to the acquisitions we made during fiscal years 2007 and 2006, our other propane segment revenues, such as appliance sales, labor and tank rentals, also improved over prior years.
 
We also completed several growth capital projects during the fiscal year ended August 31, 2007 including the Cleburne to Carthage pipeline that extends from Cleburne, Texas to the Carthage Hub in East Texas and the Godley plant. In addition to our internal growth projects we also continued to integrate the Titan operations that were acquired in June 2006 and successfully completed the acquisition of the Transwestern pipeline in a two-step process in December 2006. The Transwestern pipeline is the first FERC-regulated pipeline for the Partnership.
 
In addition, we continued to secure long-term financing for ETP. ETP successfully raised $800 million in long-term debt with interest rates ranging from 6.125% to 6.625% and maturities ranging from 10 to 30 years. ETP also received proceeds of $1.2 billion from the sale of our common units during the year ended August 31, 2007. These proceeds were used principally to finance the Transwestern acquisition and to repay indebtedness incurred with the Titan acquisition which closed in June 2006. We also increased our borrowing capacity on our revolving credit facility in June 2007 from $1.5 billion to $2.0 billion (with an option to increase to $3.0 billion). The increased capacity will provide us with the liquidity needed to complete our previously announced expansion projects.


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Trends and Outlook
 
Looking to fiscal 2008, we believe our operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion activity completed during fiscal year 2007, additional capacity resulting from pipeline projects expected to be completed within the next twelve to eighteen months, and incremental earnings related to the recently acquired Transwestern pipeline. In addition, we recently acquired the Canyon Gathering System in the Uinta-Piceance basins of Utah and Colorado which will provide for continued expansion into natural gas producing regions of the United States.
 
Analytical Analysis
 
The following is a discussion of our historical financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto incorporated by reference in this prospectus supplement.
 
The comparability of our consolidated financial statements is affected by the Parent Company’s purchase of common units and Class F units (subsequently converted to common units) of ETP in February 2006, the Parent Company’s purchase of Class G units of ETP in November 2006 (subsequently converted to common units), the Parent Company’s purchase of the remaining incentive distribution rights, or IDRs, of ETP from Energy Transfer Investments, L.P., or ETI, in November 2006, ETP’s 100% acquisition of Transwestern on December 1, 2006 (and the acquisition of 50% of CCE Holdings, LLC, or CCEH, in November 2006), the acquisition of Titan in June 2006 and the HPL System in January 2005 and the sale of ETC Oklahoma, or Elk City, in April 2005. See Note 2 to our consolidated financial statements incorporated by reference in this prospectus supplement for a detailed discussion of our significant acquisitions and dispositions during fiscal years 2007, 2006 and 2005. The comparability is also affected by fluctuation in natural gas prices, mainly in our producer services’ gas sales and purchases and natural gas sales and purchases on our HPL System. Since we buy and sell natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our gas sales and purchases tend to be higher when natural gas prices are high and our gas sales and purchases tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues, trading activities, and basis differences between market hubs.
 
The acquisition of Transwestern resulted in a significant increase in our property, plant and equipment, intangible assets and goodwill from August 31, 2006 to August 31, 2007 (see Note 2 to the consolidated financial statements incorporated by reference in this prospectus supplement). The increase from August 31, 2006 to August 31, 2007 in our long-term debt was due to debt issued in connection with and debt assumed in the Transwestern acquisition, approximately $1.0 billion in growth capital expenditures incurred during fiscal year 2007, and borrowings to finance the Parent Company’s purchase of Class G units from ETP.
 
Analysis of Operating Data — Volumes
 
Midstream
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Natural gas MMBtu/d
    941,140       1,552,753       1,578,833  
NGLs Bbls/d
    25,657       10,425       12,707  
 
  •  For the year ended August 31, 2007, the decrease in natural gas volumes sold was principally due to less favorable market conditions during fiscal 2007 and increased utilization of capacity on our transportation pipelines by third parties resulting in lower sales volumes conducted by our producer services’ operations. The increase in NGL sales volumes was principally due to the completion of our Godley plant during 2007 and favorable market conditions to process and extract NGLs during fiscal 2007 compared to the same period last year.


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  •  For the year ended August 31, 2006, natural gas sales volumes decreased compared to the year ended August 31, 2005 principally due to less marketing activity by our producer services’ operations towards the latter half of fiscal year 2006 and a change in contract mix with one of our major producers where we now charge a fee to gather, process and transport natural gas rather than buying and selling the natural gas on our behalf. Our NGL sales volumes vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The decrease in NGL sales volumes is principally due to a change in contract mix as noted above and the election to by-pass our processing plant as a result of less favorable market conditions during the second fiscal quarter of the year ended August 31, 2006.
 
Intrastate Transportation and Storage
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Natural gas MMBtu/d — transported
    6,124,423       4,633,069       3,495,434  
Natural gas MMBtu/d — sold
    1,400,753       1,580,638       1,361,729  
 
  •  For the year ended August 31, 2007, transported natural gas volumes increased due to our continued efforts to secure more long-term shipper contracts, the completion of the Cleburne to Carthage pipeline, and increased demand to transport gas out of the Barnett Shale and Bossier Sands producing regions. Natural gas sales volumes on the HPL System for the year ended August 31, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials and due to the new CenterPoint contract that commenced on April 1, 2007. Under the previous contract, we sold and delivered natural gas to CenterPoint for a bundled price. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas capacity in our Bammel storage facility. As such, we now account for these activities as natural gas transported rather than natural gas sold.
 
  •  For the year ended August 31, 2006, transported natural gas volumes increased by 1,137,635 MMBtu/d. The increase in transportation volumes is principally due to the increased volumes experienced in the Oasis pipeline, ET Fuel System and East Texas pipeline as a result of our effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Additionally, warmer weather during the 2006 fiscal year resulted in an increase in demand for natural gas. The higher temperatures required more demand for natural gas to be used by electricity-producing power plants connected to our assets. Natural gas sales volumes on the HPL System for the year ended August 31, 2006 increased 218,909 MMBtu/d compared to the year ended August 31, 2005, principally due to increased marketing efforts with our existing and new customers and increased well connects which has increased our supply on the HPL System.
 
Interstate Transportation
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Natural gas MMBtu/d — transported
    1,802,109              
Natural gas MMBtu/d — sold
    19,680              
 
  •  The increase was due to the 100% acquisition of Transwestern on December 1, 2006.
 
Retail Propane
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Retail propane gallons sold (in thousands)
    604,269       429,118       406,334  


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  •  The retail propane operations realized significant increases in gallons sold in the year ended August 31, 2007 as compared to the year ended August 31, 2006 (a 175.2 million net gallon increase) primarily due to the Titan acquisition in June 2006. The combination of below normal degree days, customer conservation, and the slow down of new home construction in our propane markets has contributed to a decrease in expected volumes sold and slowed internal growth. The overall weather in our areas of operations during the year ended August 31, 2007 was 10.6% warmer than the year ended August 31, 2006 and 7.2% warmer than normal.
 
  •  The 22.8 million net gallon increase in retail propane gallons sold for the year ended August 31, 2006, compared to the year ended August 31, 2005, includes a 24.5 million gallon increase due to the Titan acquisition for the months of June, July and August 2006, 15.9 million gallons were added through other propane acquisitions, offset by a decrease of 17.6 million gallons related to warm weather and higher propane commodity prices. The weather in our areas of operations during the year ended August 31, 2007 was 3.5% warmer than the year ended August 31, 2005 and 10.6% warmer than normal.
 
Analysis of Results of Operations
 
In the following analysis of results of operations, tabular dollar amounts are expressed in thousands.
 
Comparison of Fiscal Years Ending August 31, 2007, 2006 and 2005
 
Parent Company Only Results
 
The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Equity in earnings of affiliates
  $ 435,247     $ 204,987     $ 141,260     $ 230,260     $ 63,727  
General and administrative expense
    8,496       55,374       1,051       (46,878 )     54,323  
Interest expense
    104,405       36,773       9,529       67,632       27,244  
Loss on extinguishment of debt
          5,060             (5,060 )     5,060  
Interest and other income (expense), net
    (2,356 )     (638 )     16,066       (1,718 )     (16,704 )
 
The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.
 
Equity in Earnings of Affiliates.  Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its Class A and Class B limited partner interests of ETP GP and its investment in ETP LLC. The increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 is directly related to the increased ownership in ETP as a result of the common, Class F and Class G unit acquisitions in February 2006 and November 2006 and the increased ownership of ETP IDRs, as discussed above, and the changes in the ETP segment income described below.
 
The change in equity in earnings of affiliates for the year ended August 31, 2006 compared to the year ended August 31, 2005 is directly related to the increased ownership of ETP as a result of the common and Class F unit acquisitions in February 2006 and the changes in the ETP segment income described below.


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The change in the Parent Company’s ownership share of ETP during fiscal years 2007, 2006 and 2005 was as follows:
 
                         
    Limited
          General
 
    Partner
          Partner
 
    Interest     IDRs     Interest  
 
Interests prior to December 2005
    31 %     100 %     2 %
December 2005 distribution to ETI
          (50 )%      
Purchase of ETP Common and Class F Units in February 2006
    2 %            
Purchase of ETP Class G Units in November 2006
    13 %            
Purchase of IDRs from ETI in November 2006
          50 %      
Interests as of August 31, 2007
    46 %     100 %     2 %
 
General and Administrative Expenses.  The decrease in general and administrative expenses of the Parent Company for the year ended August 31, 2007 compared to the year ended August 31, 2006 and the increase in general and administrative expenses for the year ended August 31, 2006 compared to the year ended August 31, 2005 is primarily due to the compensation expense of $52.9 million recorded in fiscal year 2006 in connection with the issuance of Class B units by the Parent Company in conjunction with its initial public offering. (See Note 7 to our consolidated financial statements incorporated by reference in this prospectus supplement).
 
Interest Expense.  The Parent Company interest expense increased for the year ended August 31, 2007 compared to 2006 primarily due to the increased borrowings to fund the acquisition of Class G units from ETP in November 2006. See “Description of Indebtedness” under “Liquidity and Capital Resources” below and Note 6 to our consolidated financial statements incorporated by reference in this prospectus supplement for more information on the Parent Company’s indebtedness.
 
The Parent Company interest expense increased for the year ended August 31, 2006 compared to 2005 because it had no significant debt prior to June 16, 2005 when it entered into a $600.0 million senior secured term loan agreement. In conjunction with its initial public offering, the Parent Company re-paid the $600.0 million senior secured term loan agreement and entered into a new revolving credit facility.
 
Loss on Extinguishment of Debt.  The Parent Company expensed $5.1 million in deferred financing costs during fiscal year 2006 in connection with the repayment of the $600.0 million senior secured term loan agreement as described above. There was no similar repayment during fiscal year 2007 or 2005.
 
Interest and Other Income, net.  In May 2005, the Parent Company exchanged 631,320 ETP common units held by the Parent Company and $1.0 million in cash for the redemption of 2,643,200 of its limited partner interests, which were then retired. A gain of $11.2 million was recorded in interest and other income, net in our consolidated statement of operations for the year ended August 31, 2005.


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Consolidated Results
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Consolidated Information:
                                       
Revenues
  $ 6,792,037     $ 7,859,096     $ 6,168,798     $ (1,067,059 )   $ 1,690,298  
Cost of sales
    5,078,206       6,568,316       5,381,515       (1,490,110 )     1,186,801  
                                         
Gross margin
    1,713,831       1,290,780       787,283       423,051       503,497  
Operating expenses
    559,600       422,989       319,554       136,611       103,435  
Selling, general and administrative
    153,512       162,615       64,057       (9,103 )     98,558  
Depreciation and amortization
    191,383       129,636       105,751       61,747       23,885  
                                         
Operating income
    809,336       575,540       297,921       233,796       277,619  
Interest expense
    (279,986 )     (150,646 )     (101,061 )     (129,340 )     (49,585 )
Loss on extinguishment of debt
          (5,060 )     (6,550 )     5,060       1,490  
Equity in earnings (losses) of affiliates
    5,161       (479 )     (376 )     5,640       (103 )
Gain (loss) on disposal of assets
    (6,310 )     851       (330 )     (7,161 )     1,181  
Interest and other income, net
    35,158       13,701       12,191       21,457       1,510  
Income tax expense
    (11,391 )     (23,015 )     (4,397 )     11,624       (18,618 )
Minority interests
    (232,608 )     (303,752 )     (96,946 )     71,144       (206,806 )
                                         
Income from continuing operations
  $ 319,360     $ 107,140     $ 100,452     $ 212,220     $ 6,688  
Income from discontinued operations, net of income tax expense
                46,294             (46,294 )
                                         
Net income
  $ 319,360     $ 107,140     $ 146,746     $ 212,220     $ (39,606 )
                                         
 
See the detailed discussion of revenues, costs of sales, gross margin and operating expense by operating segment below.
 
Interest Expense.  For the year ended August 31, 2007 compared to the year ended August 31, 2006, interest expense increased $129.3 million. The principal factor for this increase is a net $67.6 million increase in interest expense related to borrowings of the Parent Company, a net $51.2 million increase in interest expense related to borrowings on the partnership’s 2006 and 2005 Senior Notes and the revolving credit facility. Borrowings increased primarily due to the financing of our growth capital expenditures and the CCEH/Transwestern and Titan acquisitions. Debt assumed in the Transwestern acquisition resulted in $12.5 million of increased interest expense. During the year ended August 31, 2006 losses of $0.1 million on interest rate swaps were recorded as an increase to interest expense. Such activity was not recognized in interest expense in the year ended August 31, 2007; rather, such activity was included in interest and other income. Hedge ineffectiveness charges increased interest expense by $1.8 million in fiscal 2007, compared to gains of $0.8 million in fiscal 2006. See Note 11 — “Price Risk Management Assets and Liabilities”, included in our consolidated financial statements incorporated by reference in this prospectus supplement for further discussion on interest rate hedges. Propane related interest decreased $5.1 million due primarily to the scheduled debt payments that have occurred between fiscal periods 2006 and 2007.
 
For the year ended August 31, 2006 compared to the year ended August 31, 2005, interest expense increased $49.6 million. The principal factor for this increase is a net $27.2 million increase in interest expense related to borrowings of the Parent Company, a net $22.1 million increase in interest expense related to borrowings on the 2005 Senior Notes and the revolving credit facility which we entered into January 2005 to refinance debt at ETC OLP and fund the HPL System acquisition, offset principally by an increase in unrealized gains and the ineffective charges of $1.2 million related to interest rate swaps. See Note 10 — “Price Risk Management Assets and Liabilities”, included in our consolidated financial statements incorporated by reference in this prospectus supplement for further discussion on interest rate hedges.


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Loss on Extinguishment of Debt.  The loss on extinguishment of debt during fiscal year 2006 is discussed above under “Parent Company Only Results.”
 
During the year ended August 31, 2005, we wrote off $6.6 million of debt issuance costs associated with the ETP debt that was repaid with the proceeds from the issuance of $750.0 million of 5.95% senior notes.
 
Equity in Earnings of Affiliates.  The increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 was due primarily to $5.1 million of equity income from our 50% ownership of CCEH for the month of November 2006. We did not have an investment in CCEH in fiscal 2006. We redeemed our investment in CCEH in connection with our Transwestern acquisition on December 1, 2006.
 
Gain (Loss) on Disposal of Assets.  The loss on disposal of assets reflected in the year ended August 31, 2007 was principally due to losses resulting from the sale of a compressor station.
 
Interest and Other Income, Net.  The increase in interest and other income for the year ended August 31, 2007 compared to the year ended August 31, 2006 is due primarily to gains on interest rate swaps that are not accounted for as cash flow hedges. Such gains were included in interest expense in fiscal 2006. Other income in fiscal year 2006 includes $7.7 million received from the favorable judgment on the SCANA litigation (see Notes 7 and 10 of our consolidated financial statements incorporated by reference in this prospectus supplement for further detail).
 
The increase in interest and other income for the year ended August 31, 2006 compared to the year ended August 31, 2005 is primarily due to $7.7 million received from the favorable judgment on the SCANA litigation (see Notes 7 and 10 of our consolidated financial statements incorporated by reference in this prospectus supplement for further detail).
 
Income Tax Expense.  As a partnership, we are not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes.
 
The decreased expense for the year ended August 31, 2007 was attributed principally to higher income from trading gains recognized by a taxable subsidiary during the year ended August 31, 2006, than was realized by such subsidiary in the current fiscal year. The decrease was partially offset by the Texas margin tax that was not effective until January 1, 2007.
 
The increased expense of $18.6 million for the year ended August 31, 2006 is attributed principally to higher income due to gains on financial derivative activity recognized by a taxable subsidiary. No similar gains were realized by such subsidiary in prior periods.
 
Minority Interest Expense from Continuing Operations.  The decrease in minority interest expense in fiscal year 2007 is attributable to the Parent Company’s acquisition of ETP limited partner interests in November 2006 (discussed above), offset by the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents partnership interests in ETP that we do not own.
 
The increase in minority interest expense in fiscal year 2006 is attributable to the increase in income from continuing operations of ETP described below that is allocated to the minority unitholders of our subsidiaries. The minority interest expense primarily represents partnership interests in ETP that we do not own.
 
Income from Discontinued Operations.  On April 14, 2005, ETP completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System. For the year ended August 31, 2005, the income from discontinued operations included the gain on sale of the Elk City System of $142.5 million, net of income taxes, and revenues of $105.5 million offset by costs and expenses of $100.0 million and minority interest expense of $101.7 million, resulting in income from discontinued operations of $46.3 million.
 
There were no discontinued operations for the years ended August 31, 2006 or 2007.
 
Segment Operating Results
 
We evaluate segment performance based on operating income (either in total or by individual segment) which we believe is an important performance measure of the core profitability of our operations. This measure represents


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the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
 
We do not include earnings from equity method unconsolidated affiliates in our measurement of operating income because such earnings have not been significant historically.
 
For additional information regarding our business segments, see Notes 1 and 14 to our consolidated financial statements incorporated by reference in this prospectus supplement.
 
Operating income by segment is as follows:
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Midstream
  $ 119,233     $ 147,564     $ 94,603     $ (28,331 )   $ 52,961  
Intrastate Transportation and Storage
    479,820       422,420       151,819       57,400       270,601  
Interstate Transportation
    95,650                   95,650        
Retail Propane
    124,263       76,055       66,902       48,208       9,153  
Other
    1,735       1,899       (683 )     (164 )     2,582  
Unallocated selling, general and administrative expenses
    (11,365 )     (72,398 )     (14,720 )     61,033       (57,678 )
                                         
Operating income
  $ 809,336     $ 575,540     $ 297,921     $ 233,796     $ 277,619  
                                         
 
We do not believe the other operating income is material for further disclosure and/or discussion.
 
Unallocated Selling, General and Administrative Expenses.  Prior to December 2006, the selling, general and administrative expenses that relate to the general operations of the Partnership were not allocated to our segments. In conjunction with the Transwestern acquisition, selling, general and administrative expenses are now allocated to the Operating Partnerships. For the year ended August 31, 2007, a net $18.4 million was allocated to the Operating Partnerships, which constituted the decrease in total unallocated selling general and administrative expenses from the year ended August 31, 2006. The decrease in the unallocated selling, general and administrative expenses due to the allocations now in place to the Operating Partnerships, is offset by increases in expenses primarily related to management incentive plans.
 
Unallocated selling, general and administrative expenses increased $57.7 million for the year ended August 31, 2006 compared to the year ended August 31, 2005. This increase is primarily attributed to compensation expense of $52.9 million recorded in connection with the issuance of Class B units by the Parent Company in conjunction with its initial public offering (see Note 7 to our consolidated financial statements), a $1.0 million increase in executive salaries due to additional staffing, a $0.4 million increase in professional fees due to our on-going efforts related to the Sarbanes-Oxley Act and other partnership expenses, and a $2.5 million increase in additional executive bonuses and non-cash compensation related to additional staffing and outstanding restricted units awards.


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Midstream
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Revenues
  $ 2,853,496     $ 4,223,544     $ 3,246,772     $ (1,370,048 )   $ 976,772  
Cost of sales
    2,632,187       4,000,461       3,102,539       (1,368,274 )     897,922  
                                         
Gross margin
    221,309       223,083       144,233       (1,774 )     78,850  
Operating expenses
    39,148       31,910       22,835       7,238       9,075  
Selling, general and administrative
    35,597       23,922       9,685       11,675       14,237  
Depreciation and amortization
    27,331       19,687       17,110       7,644       2,577  
                                         
Segment operating income
  $ 119,233     $ 147,564     $ 94,603     $ (28,331 )   $ 52,961  
                                         
 
Gross Margin.  For the year ended August 31, 2007, midstream’s gross margin decreased by $1.8 million primarily due to the net effect of the following factors:
 
  •  Decrease in net trading revenues of $17.9 million. During the fiscal 2006 period, we recognized trading gains resulting principally from commodities futures positions that benefited from market anomalies following the hurricanes that struck the Texas and Louisiana coasts in August and September 2005. Trading activities during the year ended August 31, 2007 resulted in a net gain of $2.2 million;
 
  •  Decrease in non-trading margin from our marketing activities of $36.0 million. Market conditions, including lower basis differentials between the west and east Texas markets and increased third-party utilization of our transportation pipeline capacity, resulted in lower sales volumes conducted by our producer services’ operations; and
 
  •  Increase in processing margin and fee-based revenue. The increase was due to the completion of our Godley plant in the first quarter of 2007, the acquisition of three gathering systems during fiscal 2007, and favorable processing conditions during fiscal 2007 compared to the same period last year at our Southeast Texas System.
 
For the year ended August 31, 2006, midstream’s gross margin increased by $78.9 million primarily due to the following factors:
 
  •  Trading gains recognized during the 2006 fiscal year resulting from commodities futures positions that benefited from market anomalies following the hurricanes that struck the Texas and Louisiana coasts in August and September 2005; and
 
  •  Increased processing margins on our Southeast Texas System as a result of favorable processing conditions during the year ended August 31, 2006 compared to the year ended August 31, 2005.
 
Operating Expenses.  Midstream operating expenses increased $7.2 million for the year ended August 31, 2007 compared to the year ended August 31, 2006. The increase was primarily driven by increased compressor rental expense of $3.7 million, increased compressor maintenance of $1.0 million, increased electricity costs of $0.9 million, and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $1.8 million. The increases were primarily driven by the Godley plant addition and the acquisition of three gathering systems during the first six months of fiscal 2007. The increases were offset by reduced measurement expense of $1.6 million due to a larger portion being allocated to the transportation segment due to the continued expansion in that segment.
 
Midstream operating expenses increased $9.1 million between the years ended August 31, 2006 and 2005 and was primarily driven by $3.2 million in increased measurement expenses, $1.1 million in increased chemical costs,


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$0.7 million in scheduled compressor and pipeline maintenance expense and pipeline integrity costs, $0.9 million in employee costs, and increases of $3.2 million in other operating expenses.
 
Selling, General and Administrative Expenses.  Midstream general and administrative expenses for the year ended August 31, 2007 increased $11.7 million compared to the year ended August 31, 2006. The increase was attributable to $13.2 million of increased legal costs primarily associated with regulatory inquiries, a $4.1 million allocation of parent company administrative expenses for overhead costs which previously had not been allocated, and increases of $3.9 million in employee-related costs such as salaries, incentive compensation and healthcare costs. The increase was offset by increases of $7.9 million in departmental costs allocated to the intrastate transportation and storage operating segment and an increase of $2.4 million in overhead costs capitalized to capital expansion projects.
 
Midstream selling, general and administrative expenses for the year ended August 31, 2006 increased $14.2 million compared to the year ended August 31, 2005. The increase was attributable to increases of $28.5 million in employee-related costs such as salaries, incentive compensation and healthcare costs, insurance premium increases of $2.2 million, increases in office-related expenses of $4.0 million, $2.7 million in increased legal, audit and consulting fees, and increases in other general and administrative expenses of $2.0 million. The increase was offset by increases of $25.2 million in departmental costs allocated to the intrastate transportation and storage operating segment. The increased costs are principally due to the growth caused by the recent acquisitions, internal growth projects and upgraded information systems.
 
Depreciation and Amortization.  The increase of $7.6 million for the year ended August 31, 2007 compared to the year ended August 31, 2006 is principally due to plant and equipment placed into service during fiscal year 2007, the completion of our Godley plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.
 
Midstream depreciation and amortization expense increased $2.6 million for the year ended August 31, 2006 compared to fiscal year 2005 principally due to the Devon acquisition in November 2004 and pipeline and equipment placed into service subsequent to August 31, 2005.
 
Intrastate Transportation and Storage
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Revenues
  $ 3,915,932     $ 5,013,224     $ 2,608,108     $ (1,097,292 )   $ 2,405,116  
Cost of sales
    3,137,712       4,322,217       2,280,082       (1,184,505 )     2,042,135  
                                         
Gross margin
    778,220       691,007       328,026       87,213       362,981  
Operating expenses
    181,133       171,312       113,166       9,821       58,146  
Selling, general and administrative
    52,844       46,520       27,021       6,324       19,499  
Depreciation and amortization
    64,423       50,755       36,020       13,668       14,735  
                                         
Segment operating income
  $ 479,820     $ 422,420     $ 151,819     $ 57,400     $ 270,601  
                                         
 
Gross Margin.  For the year ended August 31, 2007 as compared to the year ended August 31, 2006, intrastate transportation and storage gross margin increased by $87.2 million, principally due to the net effect of the following:
 
  •  Volumes.  Overall volumes on our transportation pipelines were higher during fiscal 2007 compared to fiscal 2006 due to the completion of the Cleburne to Carthage pipeline, continued efforts to secure long-term shipper contracts, increased demand to transport natural gas from the Barnett Shale and Bossier Sands producing regions, and a colder winter in fiscal 2007. Transportation fees increased approximately


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  $61.0 million for the year ended August 31, 2007 compared to the year ended August 31, 2006. Retention revenue increased approximately $35.1 million due to increased volumes transported on our pipelines;
 
  •  Lower natural gas prices.  Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $5.00 to $12.00/MMBtu during the year ended August 31, 2006 to $4.00 to $7.00/MMBtu during the same period this year resulting in a decrease in revenue by $28.8 million;
 
  •  Increase in storage margin of $26.0 million.  The increase was due to approximately $40.0 million in margin recognized on 17.5 Bcf more volume withdrawn from our Bammel storage facility in fiscal 2007 than in fiscal 2006 and a significant loss on settled derivatives during fiscal 2006. These increases were offset by approximately $18.0 million in margin on gas sold from our Bammel storage facility and delivered to a customer in September 2005. There were no similar sales during the year ended August 31, 2007; and
 
  •  Decrease in margin of $28.7 million related to well head volumes.  As discussed above, we purchase natural gas from producers at a discount to a specified price and resell to customers at an index price. We experienced lower volumes and lower natural gas prices during the year ended August 31, 2007 compared to the same period last year.
 
For the year ended August 31, 2006 as compared to fiscal year 2005, intrastate transportation and storage gross margin increased by $363.0 million, principally due to the following:
 
  •  Increased volumes and prices.  The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy Hub and our strategy to pursue additional volumes on our transportation pipeline systems. The price differential between the Waha and Katy market hubs increased between the 2005 and 2006 fiscal years, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable. We also successfully secured more firm contracts as evidenced by our transportation agreement with XTO (see Note 10 to our consolidated financial statements incorporated by reference in this prospectus supplement). In addition, our Fort Worth Basin expansion, completed in May 2005, allowed shippers to move more gas from the Barnett Shale. Our margins for the year ended August 31, 2006 were also affected favorably by higher than normal temperatures during the year ended August 31, 2006 in regions where our assets are located. The higher temperatures increased demand for natural gas to be used by electricity-producing power plants connected to these assets. Furthermore, our margin was favorably impacted by an increase in fuel retention fees due to the increase in volumes on our transportation pipelines and an increase in average natural gas prices during the 2006 fiscal year compared to the 2005 fiscal year. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees;
 
  •  The acquisition of the HPL System in January 2005.  The results for the year ended August 31, 2005 contain seven months of the HPL System’s operating results as compared to twelve months of the HPL System operating results included in fiscal year 2006. For the year ended August 31, 2006, the HPL System margin was principally affected by the sale of natural gas held in storage during the winter months when demand for natural gas is strong, increased margins resulting from favorable pricing between the west and east markets in the Houston Ship Channel, and hedging gains as noted below. The favorable pricing was attributed to the effects of the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005; and
 
  •  Discontinued Hedge Accounting.  In January and February 2006, we discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in our Bammel storage facilities. The discontinuation resulted from our determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable to occur by the end of the originally specified time period, or


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  within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during January 2006 through March 2006. As a result, during the year ended August 31, 2006, we recognized previously deferred unrealized gains of approximately $84.7 million from the discontinuation of hedge accounting.
 
Operating Expenses.  Intrastate transportation and storage operating expenses increased $9.8 million when comparing the year ended August 31, 2007 to the year ended August 31, 2006. The increase was principally attributable to increases of $12.5 million in pipeline and compressor maintenance and compressor rentals, $3.6 million in property taxes, and $2.3 million in employee-related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a decrease of $11.0 million in fuel consumption which was due to higher natural gas prices in the early part of fiscal 2006.
 
For the year ended August 31, 2006 compared to fiscal year 2005, intrastate transportation and storage operating expenses increased $58.1 million. The increase was principally attributable to increases of $32.4 million in operating expenses related to the HPL System acquisition, $19.5 million related to compressor fuel consumption resulting from higher throughput volumes and increased gas prices during the year ended August 31, 2006, $2.1 million in property taxes, $2.5 million in pipeline maintenance, $1.4 million in compressor rental and maintenance, and $1.3 million in increased employee costs, offset by a decrease of $1.1 million in other operating expenses.
 
Selling, General and Administrative Expenses.  Intrastate transportation and storage general and administrative expenses increased $6.3 million for the year ended August 31, 2007 compared to the year ended August 31, 2006 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects.
 
For the year ended August 31, 2006 compared to the year ended August 31, 2005, intrastate transportation and storage selling, general and administrative expenses increased $19.5 million principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL System acquisition and an increase in salaries and wages, incentive compensation expense, and other employee-related expenses.
 
Depreciation and Amortization.  Intrastate transportation and storage depreciation and amortization expense increased $13.7 million for the year ended August 31, 2007 compared to the year ended August 31, 2006, principally due to plant and equipment placed into service during fiscal year 2007.
 
For the year ended August 31, 2006 compared to the year ended August 31, 2005, intrastate transportation and storage depreciation and amortization expense increased $14.7 million, principally due to the HPL System acquisition in January 2005, the Fort Worth Basin Pipeline completed in May 2005 and additional compressors and equipment added to existing systems.
 
Interstate Transportation
 
                         
    Years Ended August 31,     Amount of
 
    2007     2006     Change  
 
Revenues
  $ 178,663     $     $ 178,663  
Operating expenses
    36,295             36,295  
Selling, general and administrative
    18,746             18,746  
Depreciation and amortization
    27,972             27,972  
                         
Segment operating income
  $ 95,650     $     $ 95,650  
                         
 
The increase in all categories between fiscal years ending August 31, 2007 and 2006 was due to the acquisition of 100% of Transwestern on December 1, 2006.


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No comparative data is presented for fiscal year 2005 as the Transwestern acquisition did not take place until fiscal year 2007.
 
Retail Propane
 
                                         
    Years Ended August 31,     Amount of Change  
    2007     2006     2005     2007-2006     2006-2005  
 
Retail propane revenues
  $ 1,179,073     $ 799,358     $ 641,071     $ 379,715     $ 158,287  
Other retail propane related revenues
    105,794       80,198       68,402       25,596       11,796  
Retail propane cost of sales
    734,204       493,642       384,186       240,562       109,456  
Other retail propane related cost of sales
    25,430       21,776       19,554       3,654       2,222  
                                         
Gross margin
    525,233       364,138       305,733       161,095       58,405  
Operating expenses
    297,469       212,188       176,277       85,281       35,911  
Selling, general and administrative
    32,668       17,859       11,067       14,809       6,792  
Depreciation and amortization
    70,833       58,036       51,487       12,797       6,549  
                                         
Segment operating income
  $ 124,263     $ 76,055     $ 66,902     $ 48,208     $ 9,153  
                                         
 
Revenues.  Retail propane revenue increased $379.7 million between the years ended August 31, 2007 and 2006, mainly due to the increase in volumes sold by customer service locations added through the Titan acquisition in June 2006. The increase in retail propane revenues was offset somewhat by weather that was 7.2% warmer than normal weather and 10.6% warmer than last year. Other retail propane related revenues increased $25.6 million for the year ended August 31, 2007 compared to fiscal year 2006 primarily due to other propane related revenues of companies we have acquired between the two years and enhanced fee generating programs in servicing our customers.
 
Of the total increase in retail propane revenue of $158.3 million between the years ended August 31, 2006 and 2005, $47.1 million is due to the increase in volumes sold by customer service locations added through the Titan acquisition in June 2006, $29.6 million is due to the increase in volumes sold by customer service locations added through other propane acquisitions and $114.4 million is due to higher selling prices. These increases were offset by a decrease of $32.8 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $11.8 million for the year ended August 31, 2006 compared to fiscal year 2005 primarily due to other propane related revenues of companies we have acquired between the two years.
 
Costs of Sales.  During the year ended August 31, 2007 compared to the year ended August 31, 2006, retail propane cost of sales increased by $240.6 million which mainly relates to the increase in gallons sold by customer service locations added through the Titan acquisition.
 
During the year ended August 31, 2006 compared to the year ended August 31, 2005, retail propane cost of sales increased by $109.5 million of which $30.8 million is a result of an overall increase in gallons sold by customer service locations added through the Titan acquisition, $18.2 million due to an overall increase in gallons sold by customer service locations added through other propane acquisitions and $80.7 million is due to higher cost of fuel, offset by a decrease of $20.2 million due to the impact of weather related volumes described above.
 
Gross Margin.  The overall increase in gross margins for the year ended August 31, 2007 compared to fiscal year 2006 is primarily related to the Titan acquisition in June 2006. The propane margin remained strong during the fiscal year ended August 31, 2007 during the periods of warmer weather and higher fuel prices. Optimization of the margins is influenced by market opportunities, independent competitors and concerns for long term retention of customers.


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The overall increase in gross margins for the year ended August 31, 2006 compared to fiscal year 2005 is a function of acquisition-related increases and higher sales prices.
 
Operating Expenses.  During the year ended August 31, 2007, operating expenses increased by $85.3 million compared to the same period last year. The increase is directly related to the operating expenses of the identifiable Titan operations. Included in these operating expenses are increases that relate to higher vehicle fuel costs and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan acquisition, and other acquisition costs related to blends and mergers of propane locations to gain forward synergies and cost savings.
 
During the year ended August 31, 2006, operating expenses increased by $35.9 million compared to fiscal 2005 due to a combination of a $21.4 million increase due to the Titan acquisition, a $9.2 million increase in our employee base from other acquisitions and annual salary increases, $3.4 million due to higher fuel costs to run our vehicles and other vehicle expenses, and a $4.7 million general increase in other operating expenses primarily from other acquisitions, offset by a $2.8 million net decrease in other operating expenses.
 
Selling, General and Administrative Expenses.  The increase in selling, general and administrative expenses for the comparable years of August 31, 2007 and 2006 is primarily due to increases from administrative expense allocations, increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition. The increase also includes increases in our IT costs as we continue to enhance our current infrastructure for our administrative and propane systems. Effective with the Transwestern acquisition in December 2006, an allocation of administrative expenses is now made to the operating partnerships, which increased the retail propane selling, general and administrative expenses by a net $7.9 million for the year ended August 31, 2007.
 
The increase in selling, general and administrative expenses for the comparable years of August 31, 2006 and 2005 is primarily due to increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding.
 
Depreciation and Amortization Expense.  The increase of $12.8 million in depreciation and amortization expense for the year ended August 31, 2007 as compared to 2006 is due primarily to the acquisition of Titan on June 1, 2006. Depreciation and amortization increased $6.5 million for the fiscal year ended August 31, 2006 as compared to August 31, 2005, primarily due to the depreciation and amortization of assets and amortizable intangibles added through acquisitions during fiscal 2006.
 
Income Taxes
 
As a limited partnership we generally are not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries, or C corporations. These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended August 31, 2007, 2006 and 2005, our non-qualifying income was not expected to, or did not, exceed the statutory limit.
 
Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a 12-month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.


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Based on the information currently available to us, we believe that we exceeded the 50% threshold on May 7, 2007, and, as a result, we have determined that our partnership terminated for federal tax income purposes on that date. Our termination also caused ETP to terminate for federal income tax purposes on that date. These terminations do not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. These terminations will require both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP will be required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the unitholders of ETP and, consequently, to our unitholders. However, elections ETP and ETE will make with respect to the amortization of certain intangible assets will have the effect of reducing the amount of taxable income that would otherwise be allocated to ETE unitholders.
 
We believe that the net effect of our tax termination and the tax termination of ETP will be an allocation for the 2007 calendar year of (i) an increased amount of taxable income as a percentage of the cash distributed to our unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our unitholders who purchased their units on or after the date of our initial public offering in February 2006. We estimate, based on our current distribution levels and various assumptions regarding the gross income and capital expenditures of ETP, that a unitholder who purchased our units on the date of our initial public offering or a new purchaser of our units would be allocated taxable income of less than 10% of the cash distributed to them for the 2008 calendar year. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our income or loss being includable in their taxable income for the year of termination.
 
As a result of the tax termination discussed above, we elected new depreciation and amortization policies for income tax purposes, which include the amortization of goodwill. As a result of the income tax regulations related to remedial income allocations, ETP’s subsidiary, HHI, which owns ETP’s Class E units, receives a special allocation of taxable income, for income tax purposes only, essentially equal to the amount of goodwill amortization deductions allocated to purchasers of ETP common units. The amount of such “goodwill” accumulated as of the date of ETP’s acquisition of Heritage Holdings, Inc., or HHI, (approximately $158 million) is now being amortized over 15 years beginning on May 7, 2007, the date of our new tax elections. ETP accounts for HHI using the treasury stock method due to its ownership of ETP’s Class E units. Due to the accounting rules outlined in SFAS 109 and related Interpretations, ETP accounts for the tax effects of the goodwill amortization and remedial income allocation as an adjustment of ETP’s HHI purchase price allocation, which effectively results in a charge to ETP’s common equity and a deferred tax benefit offsetting the current tax expense resulting from the remedial income allocation for tax purposes. For the year ended August 31, 2007, this resulted in a current tax expense and deferred tax benefit (with a corresponding charge to common equity as an adjustment of the purchase price allocation) of approximately $1.2 million. As of August 31, 2007, the amount of tax goodwill to be amortized over the next 15 years for which HHI will receive a remedial income allocation is approximately $155 million.
 
The difference between the statutory rate and the effective rate is summarized as follows:
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Federal statutory tax rate
    35.00 %     35.00 %     35.00 %
State income tax rate net of federal benefit
    1.25 %     3.10 %     3.56 %
Earnings not subject to tax at the Partnership level
    (34.23 )%     (32.80 )%     (36.58 )%
                         
Effective tax rate
    2.02 %     5.30 %     1.98 %
                         


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Income tax expense consists of the following current and deferred amounts:
 
                         
    Years Ended August 31,  
    2007     2006     2005  
 
Continuing operations
                       
Current provision:
                       
Federal
  $ 7,896     $ 27,640     $ 5,042  
State
    10,432       1,987       963  
                         
      18,328       29,627       6,005  
Deferred provision (benefit):
                       
Federal
    (7,494 )     (6,227 )     (2,015 )
State
    557       (385 )     407  
                         
Total tax provision on continuing operations
    (6,937 )     (6,612 )     (1,608 )
      11,391       23,015       4,397  
Discontinued operations
                       
Current income tax expense:
                       
Federal
                1,570  
State
                    259  
                         
Total Tax Provision
  $ 11,391     $ 23,015     $ 6,226  
                         
 
On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the year ended August 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $6.9 million. There is no comparable state tax expense for the years ended August 31, 2006 or 2005.
 
Liquidity and Capital Resources
 
Parent Company Only
 
The Parent Company currently has no separate operating activities apart from those conducted by the Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below.
 
The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP.
 
In February 2006, the Parent Company completed its initial public offering of 24,150,000 common units at a price of $21.00 per unit. Proceeds from the initial public offering 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.


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On July 17, 2006, the Parent Company purchased 9,642,757 of its common units from one of the common unitholders for an aggregate purchase price of approximately $237.8 million. The purchase was funded with a combination of borrowings from the Parent Company’s $500.0 million Revolving Credit Facility and a new $150.0 million Senior Secured Term Loan Facility which is discussed under “Description of Indebtedness” below.
 
On November 1, 2006, ETP issued approximately 26.1 million of its Class G units to the Parent Company for $1.2 billion, at a price of $46.00 per unit based upon a market discount from the closing price of ETP’s common units on October 31, 2006. The ETP Class G units were issued to the Parent Company pursuant to a customary agreement, and the Parent Company was granted registration rights. ETP used the proceeds of $1.2 billion in order to fund a portion of the Transwestern pipeline acquisition and to repay indebtedness ETP incurred in connection with the Titan acquisition. The terms of the Class G units were substantially similar to those of ETP’s common units, as discussed in Note 7 to our consolidated financial statements. On May 1, 2007, the ETP Class G units converted to ETP common units upon approval of the ETP common unitholders.
 
In a separate but related transaction, on November 1, 2006, ETE acquired from ETI, the remaining 50% ownership of Class B limited partner interests in ETP GP, which have the right to distributions of general partner IDRs of ETP, resulting in ETE now owning 100% of the IDRs. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C units for the ETP GP Class B interests owned by ETI and the assumption of ETI debt of $70.5 million. See Note 2 of our condensed consolidated financial statements for discussion of the accounting for the transaction with ETI.
 
On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. This facility was amended on December 4, 2006 to consolidate ETE’s existing term loan of $150 million with the new $1.3 billion term loan to form one facility totaling $1.45 billion with a maturity date of November 1, 2012. The Parent Company used the proceeds of the loan to acquire the Class G units of ETP, refinance assumed debt and for liquidity and general Partnership purposes.
 
On November 28, 2006 the Parent Company sold 7,789,133 common units to a group of institutional investors in a private placement at a price of $27.41 per unit, resulting in net proceeds of approximately $213.5 million. The Parent Company used the proceeds to repay indebtedness under its credit facility.
 
On March 2, 2007 the Parent Company issued approximately 5.0 million common units in a private placement to a group of institutional investors. The units were issued at a price of $31.96 per unit resulting in approximately $160.0 million in net proceeds to the Parent Company. The proceeds were used to repay Parent Company indebtedness.
 
In connection with the November 2006 and March 2007 private placement of units, the Parent Company executed registration rights agreements under which it agreed to file a shelf registration statement under the Securities Act of 1933 within 90 days of closing of the private placement. The Form S-3 shelf registration statement was filed on September 25, 2007, and provides for a primary offering of common units up to a total of $2.0 billion and a secondary offering of approximately 66.6 million common units by selling unitholders.
 
ETP
 
ETP’s ability to satisfy its obligations and pay distributions to its partners will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.
 
ETP’s future capital requirements will generally consist of:
 
  •  maintenance capital expenditures, which include capital expenditures made to connect additional wells to its natural gas systems in order to maintain or increase throughput on existing assets, for which we expect to expend approximately $70 million in the next fiscal year and capital expenditures to extend the useful lives of ETP’s propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet for which ETP expects to expend approximately $35 million in the next fiscal year;


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  •  growth capital expenditures, mainly for constructing new pipelines, processing plants, treating plants and compression for the midstream and intrastate transportation and storage segment for which we expect to expend approximately $1.0 billion in the next fiscal year. We also expect to spend approximately $800 million in our interstate segment for constructing new pipelines and pipeline expansion and approximately $30 million for customer propane tanks in the next fiscal year; and
 
  •  acquisition capital expenditures including acquisition of new pipeline systems and propane operations. As a partnership practice, we do not budget for acquisitions.
 
ETP believes that cash generated from the operations of its businesses will be sufficient to meet anticipated maintenance capital expenditures. ETP will initially finance all capital requirements by cash flows from operating activities. To the extent that its future capital requirements exceed cash flows from operating activities:
 
  •  maintenance capital expenditures may be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable;
 
  •  growth capital expenditures may be financed by the proceeds of borrowings under the existing ETP credit facilities, long-term debt, the issuance of additional common units or a combination thereof; and
 
  •  acquisition capital expenditures may be financed by the proceeds of borrowings under the existing ETP credit facilities, other ETP lines of credit, long-term debt, the issuance of additional common units or a combination thereof.
 
The assets used in ETP’s natural gas operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than those expenditures necessary to maintain the service capacity of ETP’s existing assets. The assets utilized in ETP’s propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond its control. However, ETP includes these factors into its anticipated growth capital expenditures for each fiscal year.
 
ETP manages its exposure to increased pipe costs by purchasing steel and reserving mill space, as projects are approved, in advance of construction. However, there is no assurance that ETP will not be impacted by increased pipe costs and limited mill space.
 
In connection with the HPL System acquisition, ETP engages in natural gas storage transactions in which it seeks to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although ETP intends to fund natural gas purchases with cash generated from operations, from time to time it may need to finance the purchase of natural gas to be held in storage with borrowings from its current credit facilities. ETP intends to repay these borrowings with cash generated from operations when the gas is sold.
 
During fiscal year 2006, ETP filed a Registration Statement on Form S-3 with the SEC to register a $1.0 billion aggregate offering price of common units. Through August 31, 2007, ETP has not made any sales under this Registration Statement.
 
Cash Flows
 
Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, including the recently acquired Transwestern and Titan operations, and other factors.


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Operating Activities.  Cash provided by operating activities during the year ended August 31, 2007, was $754.5 million as compared to cash provided by operating activities of $310.8 million for the year ended August 31, 2006. The net cash provided by operations for the year ended August 31, 2007 consisted of net income of $319.4 million, non-cash charges of $187.0 million, principally minority interests, non cash unit-based compensation expense and depreciation and amortization, and cash from changes in operating assets and liabilities of $248.1 million. Various components of operating assets and liabilities changed significantly from the prior period due to factors such as the change in value of price risk management assets and liabilities, variance in the timing of accounts receivable collections, payments on accounts payable, and the timing of the purchase and sale of inventories related to the propane and intrastate transportation and storage operations.
 
Investing Activities.  Cash used in investing activities during the year ended August 31, 2007 of $2.2 billion is comprised primarily of cash paid for our investment in CCEH of $1.0 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $90.7 million and $1.0 billion invested for growth capital expenditures (including the payment of $9.4 million accrued in prior periods) of which $974.6 million related to natural gas operations and $32.9 million to propane operations. We also incurred $89.2 million in maintenance expenditures needed to sustain operations of which $63.2 million related to natural gas operations and $26.0 million to propane.
 
Financing Activities.  Cash provided by financing activities was $1.5 billion for the year ended August 31, 2007. We received $372.4 million in proceeds from the sale of common units. We had a net increase of $1.4 billion in our debt level, of which $1.0 billion was used to fund the purchase of the member interests of CCEH and the remainder was used to repay the indebtedness we incurred in connection with the Titan acquisition as discussed in Note 2 to our consolidated financial statements. On October 23, 2006, we received net proceeds of $791.0 million from the issuance of senior notes (see Note 6 to our consolidated financial statements incorporated by reference in this prospectus supplement) which we used to repay borrowings under the partnership’s revolving credit facility. In January and February 2007, we borrowed a total of approximately $307.0 million on our Revolving Credit Facility to fund required pre-payments of the debt we assumed in connection with our acquisition of Transwestern. In May 2007, Transwestern issued $307.0 million principal of Senior Unsecured Series Notes from which we used $295.0 million to repay borrowings and accrued interest outstanding under the partnership’s revolving credit facility and $12.0 million for general partnership purposes. During the year ended August 31, 2007, we paid $23.3 million debt issue costs related to debt issuances. During the year ended August 31, 2007 we paid distributions of $277.0 million to our partners.
 
Financing and Sources of Liquidity
 
Description of Indebtedness
 
ETE’s consolidated indebtedness as of August 31, 2007 includes the Parent Company’s Senior Secured Credit Agreement which includes a $1.45 billion Senior Secured Term Loan Facility available through November 1, 2012 and a $500 million Senior Secured Revolving Credit Facility available through February 8, 2011. ETP has $750 million in principal amount of 5.95% Senior Notes due 2015, $400 million in principal amount of 5.65% Senior Notes due 2012, $400 million in principal amount of 6.125% Senior Notes due 2017 and $400 million in principal amount of 6.625% Senior Notes due 2036, collectively, the ETP Senior Notes, a revolving credit facility that allows for borrowings of up to $2.0 billion (expandable to $3.0 billion) available through June 20, 2012, or the ETP Credit Facility, and a $310 million, 364-day term loan credit facility executed on October 5, 2007 (discussed below). ETP also assumed long-term debt in connection with the Transwestern acquisition which is discussed in detail below. We also currently maintain a separate credit facility for HOLP. The terms of our indebtedness and our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements. Failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and our subsidiaries’ ability to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of August 31, 2007, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.


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Parent Company Indebtedness
 
On December 4, 2006, the Parent Company entered into a Second Amendment to Amended and Restated Credit Agreement, dated December 4, 2006, as amended, the Parent Company Credit Agreement, with BNP, CitiCorp North American, JPMorgan Chase, UBS Securities and Wachovia Capital Markets, with Wachovia Bank, NA as Administrative Agent. The Parent Company Credit Agreement provided for the consolidation of the three separate outstanding Term Loans into a single $1.45 billion Term Loan Facility and a Term Loan Maturity Date of November 1, 2012. The Parent Company used the proceeds of the loan to acquire the Class G units of ETP, refinance debt assumed in the transaction with ETI discussed above and for liquidity and general Partnership purposes.
 
The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility, or the Parent Company Revolving Credit Facility, available through February 8, 2011. The Parent Company Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $10.0 million and a daily rate based on London Interbank Offered Rate, or LIBOR.
 
The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of August 31, 2007 was $1.6 billion with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company’s debt facilities as of August 31, 2007 was $378.5 million. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to bank syndication’s approval, to expand the facility’s capacity up to an additional $100.0 million.
 
The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio which is currently at Level III or 0.375%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. At August 31, 2007, the weighted average interest rate was 7.1061% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1.45 billion Senior Secured Term Loan Facility.
 
The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries including its ownership of 62.5 million ETP common units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% general partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership in ETP GP. The financial covenants contained in the revolving credit facility include a leverage ratio test, a consolidated leverage ratio test, an interest coverage ratio test and a value-to-loan ratio. Please see Note 6 to our consolidated financial statements incorporated by reference in this prospectus supplement for further discussion of the covenants.
 
ETP Indebtedness
 
ETP Senior Notes
 
On October 23, 2006, ETP closed the issuance, under a $1.5 billion S-3 Registration Statement, of $400.0 million of 6.125% senior notes due 2017 and $400.0 million of 6.625% senior notes due 2036. ETP used the net proceeds of approximately $791.0 million from the issuance of the notes to repay borrowings and accrued interest outstanding under its previously existing revolving credit facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the 2017 senior notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 senior notes is payable semiannually on April 15 and October 15 of each year, beginning April 15, 2007.
 
The ETP Senior Notes represent senior unsecured obligations and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. In connection with the Partnership entering into the credit agreement for the ETP Credit Facility in July 2007 as described in more detail below, all guarantees by ETC OLP, Titan and all of their direct and indirect wholly-owned subsidiaries for the ETP Senior Notes were released and


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discharged. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
 
The ETP Senior Notes were issued under an indenture containing covenants, which include covenants that restrict our ability to, subject to certain exceptions, incur debt secured by liens, engage in sale and leaseback transactions or merge or consolidate with another entity or sell substantially all of our assets.
 
Transwestern Assumed Long-Term Debt and Senior Unsecured Series Notes
 
On December 1, 2006 ETP assumed the following long-term debt in connection with the Transwestern acquisition:
 
         
5.39% Notes due November 17, 2014
  $ 270,000  
5.54% Notes due November 17, 2016
    250,000  
         
Total long-term debt outstanding
    520,000  
Unamortized debt discount
    (623 )
         
Total long-term debt assumed
  $ 519,377  
         
 
No principal payments are required under any of the Transwestern debt agreements prior to their respective maturity dates. Due to a change in control provision in Transwestern’s debt agreements, Transwestern was required to pre-pay $292 million and $15 million in February and March 2007, respectively. These payments were financed with borrowings from the ETP’s previously existing revolving credit facility.
 
In May 2007, Transwestern issued a total of $307 million aggregate principal amount of Senior Unsecured Series Notes, or the Transwestern Series Notes, comprised of the following:
 
                     
Principal
    Interest Rate     Maturity Date  
 
$ 82,000       5.64 %     May 24, 2017  
  150,000       5.89 %     May 24, 2022  
  75,000       6.16 %     May 24, 2037  
 
The Partnership used $295 million of the proceeds received to repay borrowings and accrued interest outstanding under its then existing revolving credit facility and $12 million for general partnership purposes. Interest is payable semi-annually, and the Transwestern Series Notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern Series Notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.
 
Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.
 
HOLP Senior Secured Notes
 
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of August 31, 2007 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.


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Revolving Credit and Short-Term Debt Facilities
 
ETP Facilities
 
ETP Credit Facility.  On July 20, 2007, we entered into the ETP Credit Facility with Wachovia Bank, National Association, as administrative agent and Bank of America, N.A., as syndication agent, and certain other agents and lenders. The ETP Credit Facility replaced our previously existing $1.5 billion revolving credit facility, and all outstanding borrowings and letters of credit under our previously existing credit facility were replaced by borrowings and letters of credit under the ETP Credit Facility. The $1.5 billion prior credit facility was then terminated. The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion at our option (subject to the approval of the administrative agent under the Amended and Restated Credit Agreement, which approval is not to be unreasonably withheld). The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments under the ETP Credit Facility). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.0 billion unless expanded to $3.0 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. The indebtedness under the ETP Credit Facility is prepayable at any time at the partnership’s option without penalty. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.
 
The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the partnership’s and certain of the partnership’s subsidiaries ability to, among other things:
 
  •  incur indebtedness;
 
  •  grant liens;
 
  •  enter into mergers;
 
  •  dispose of assets;
 
  •  make certain investments;
 
  •  make Distributions during certain Defaults and during any Event of Default;
 
  •  engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
 
  •  engage in transactions with affiliates;
 
  •  enter into restrictive agreements; and
 
  •  enter into speculative hedging contracts.
 
This credit agreement also contains a financial covenant that provides that on each date the Partnership makes a Distribution, the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified Acquisition Period (as such terms are used in this credit agreement).
 
As of August 31, 2007, there was a balance of $969.4 million in revolving credit loans (including $107.4 million in Swingline loans) and $57.3 million in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2007, was 6.01%. The total amount available under the ETP Credit Facility, as of August 31, 2007, which is reduced by any amounts outstanding under the swingline loan and letters of credit, was $973.3 million. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the partnership’s subsidiaries. In connection with entering into the credit agreement for the ETP Credit Facility, all guarantees by ETC OLP, Titan and their direct and indirect wholly-owned subsidiaries of the ETP Senior Notes were released and discharged. The indebtedness under the ETP Credit Facility has the same priority of payments as our other current and future unsecured debt.


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ETP Term Loan.  On October 5, 2007, ETP entered into a credit agreement providing for a $310 million, 364-day term loan credit facility, or the Term Loan Agreement. Borrowings under the Term Loan Agreement were used to fund the purchase price for the Canyon acquisition and for general corporate purposes. The facility is a single draw term loan with an applicable Eurodollar rate plus 0.600% per annum based on our current rating by the rating agencies or at Base Rate for designated period. The indebtedness under the Term Loan Agreement is unsecured and is not guaranteed by any of our subsidiaries. Borrowings under the Term Loan Agreement, upon proper notice to the administrative agent, may be prepaid in whole or in part without premium or penalty. The Term Loan Agreement requires any proceeds received from debt or equity issuance, assets sales, or accordion increases be used to make a mandatory prepayment on the outstanding loan balance. The Term Loan Agreement contains covenants that are similar to the covenants of our existing ETP Credit Facility.
 
Prior ETP Credit Facilities.  On September 25, 2006, ETP exercised the accordion feature of its previously existing revolving credit facility and expanded the amount of the facility from $1.3 billion to $1.5 billion. Amounts borrowed under ETP’s previously existing revolving credit facility bore interest at a rate based on either a Eurodollar rate or a prime rate. ETP’s previously existing revolving credit facility had a swingline loan option with a maximum borrowing of $75.0 million at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varied based on ETP’s credit rating and the maximum fee was 0.175%. ETP’s previously existing revolving credit facility was fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries of ETP. ETP’s previously existing revolving credit facility was unsecured and had equal rights to holders of ETP’s other current and future unsecured debt.
 
On October 18, 2006 ETP paid and retired a $250 million unsecured revolving credit facility which matured under its terms on December 1, 2006. Amounts borrowed under this facility bore interest at a rate based on either a Eurodollar rate or a base rate. The maximum commitment fee payable on the unused portion of the facility was 0.25%. The $250 million revolving credit facility was fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.
 
HOLP Facilities
 
Effective August 31, 2006, HOLP entered into the Fourth Amended and Restated Credit Agreement, a $75 million Senior Revolving Facility available through June 30, 2011, or the HOLP Facility, which may be expanded to $150 million. The HOLP Facility has a swingline loan option with a maximum borrowing of $10 million at a prime rate. Amounts borrowed under the HOLP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Facility (total book value as of August 31, 2007 of approximately $1.2 billion). There was no balance outstanding on the HOLP Facility as of August 31, 2007. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Facility. There were outstanding letters of credit under the HOLP Facility of $1.0 million at August 31, 2007. The sum of the loans made under the HOLP Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the maximum amount of the HOLP Facility.
 
Debt Covenants
 
The agreements for each of the Senior Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The most restrictive of these covenants require us to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA, as defined in the agreements, for the specified four fiscal quarter period of not greater than 5.0 to 1.0, with a permitted increase to 5.5 to 1.0 during a specified Acquisition Period (these terms are defined in the credit agreement related to the ETP Credit Facility), Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the credit agreement related to the ETP


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Credit Facility and the note agreements related to the HOLP Notes) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating these ratios, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestitures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The note agreements related to the HOLP Notes further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.
 
Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the Note Agreements could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the partnership’s, Transwestern’s and HOLP’s debt agreements as of August 31, 2007.
 
Contractual Obligations
 
The following table summarizes our long-term debt and other contractual obligations as of August 31, 2007:
 
                                         
    Payments Due by Period  
          Less Than 1
                More Than 5
 
Contractual Obligations
  Total     Year     1-3 Years     3-5 Years     Years  
 
Long-term debt
  $ 5,245,739     $ 47,063     $ 85,955     $ 1,144,908     $ 3,967,813  
Interest on fixed rate long-term debt(a)
    1,952,088       167,744       354,086       340,718       1,089,540  
Payments on derivatives
    6,197       5,233       964              
Purchase commitments(b)
    717,350       607,854       109,496              
Operating lease obligations
    98,788       13,492       27,249       29,877       28,170  
                                         
Totals
  $ 8,020,162     $ 841,386     $ 577,750     $ 1,515,503     $ 5,085,523  
                                         
 
 
(a) Fixed rate interest on long-term debt includes the amount of interest due on our fixed rate long-term debt. These amounts do not include interest on our variable rate debt obligations which include our Revolving Credit Facilities and Revolving Credit Facility Swingline Loan options. As of August 31, 2007, variable rate interest on our outstanding balance of variable rate debt of $2.5 billion would be $180.6 million on an annual basis. See Note 6 — “Debt Obligations” to the consolidated financial statements incorporated by reference in this prospectus supplement for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt.
(b) We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for propane and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the August 31, 2007 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Quantities shown in the table represent our volume commitments and estimated payment obligations under these contracts for the periods indicated.


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In August 2007 and in connection with a reimbursable agreement entered into by MEP with a financial institution, ETP executed a percentage guaranty with the same financial institution whereby it would be liable for its 50% of any defaulted payments not made by MEP, plus interest. The reimbursable agreement has a commitment up to $197.0 million, as amended, and expires in September 2008.
 
Cash Distributions
 
Cash Distributions Paid by the Parent Company
 
Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner that is necessary or appropriate to provide for future cash requirements.
 
Distributions declared since the Parent Company’s initial public offering in February 2006 are as follows:
 
                 
    Record Date   Payment Date   Amount per Unit  
 
Fiscal Year 2007
  July 2, 2007   July 19, 2007   $ 0.3725  
    April 9, 2007   April 16, 2007     0.3560  
    January 4, 2007   January 19, 2007     0.3400  
    October 5, 2006   October 19, 2006     0.3125  
Fiscal Year 2006
  June 30, 2006   July 19, 2006   $ 0.2375  
    March 31, 2006   April 19, 2006     0.0578  
 
On September 25, 2007, the Parent Company announced the declaration of a cash distribution for the fourth quarter ended August 31, 2007 of $0.39 per common unit, or $1.56 annually, an increase of $0.07 per common unit on an annualized basis. The distribution was paid on October 19, 2007 to unitholders of record at the close of business on October 5, 2007.
 
The total amount of distributions (all from Available Cash from the Parent Company’s operating surplus) declared during the years ended August 31, 2007, 2006 and 2005 are as follows:
 
                         
    2007     2006     2005  
 
Limited Partners
                       
Limited Partners(a)
  $ —       $ 34,010     $ 666,751  
Common Units
    246,136       65,905        
Class B Units
    1,645       745        
Class C Units
    28,261              
General Partner
    955       599       4,861  
                         
Total distributions declared
  $ 276,997     $ 101,259     $ 671,612  
                         
 
 
(a) Represents distributions prior to the Parent Company’s initial public offering.
 
Cash Distributions Received by the Parent Company
 
Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s 2% general partner interest, 100% of ETP’s incentive distribution rights and ETP common units held by the Parent Company.


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The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and IDRs for the years ended August 31, 2007, 2006 and 2005 is as follows:
 
                         
    2007     2006     2005  
 
Limited Partners Interests
  $ 174,969     $ 80,203     $ 57,671  
General Partner Interest
    12,701       6,931       4,237  
Incentive Distribution Rights
    183,056       64,436       27,971  
Less holdback(a)
          (2,287 )     (8,182 )
                         
Total distributions received from ETP
  $ 370,726     $ 149,283     $ 81,697  
                         
 
 
(a) Represents amounts held back for reimbursement of expenses and contributions required to maintain ETP GP’s 2% general partner interest in ETP.
 
Cash Distributions Paid by ETP
 
ETP will use its cash provided by operating and financing activities from the Operating Partnerships to provide distributions to its unitholders. Under ETP’s partnership agreement, ETP will distribute to its partners within 45 days after the end of each fiscal quarter, an amount equal to all of its Available Cash (as defined in ETP’s partnership agreement) for such quarter. Available Cash generally means, with respect to any quarter of ETP, all cash on hand at the end of such quarter less the amount of cash reserves established by ETP’s general partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. ETP’s commitment to its unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for its operations.
 
Distributions declared by ETP during the years ended August 31, 2007, 2006 and 2005 are summarized as follows:
 
                 
    Record Date   Payment Date   Amount per Unit  
 
Fiscal Year 2007
  July 2, 2007   July 16, 2007   $ 0.80625  
    April 6, 2007   April 13, 2007     0.78750  
    January 4, 2007   January 15, 2007     0.76875  
    October 5, 2006   October 16, 2006     0.75000  
Fiscal Year 2006
  June 30, 2006   July 14, 2006   $ 0.63750  
    June 30, 2006(1)   July 14, 2006     0.03250  
    March 24, 2006   April 14, 2006     0.58750  
    January 4, 2006   January 13, 2006     0.55000  
    September 30, 2005   October 14, 2005     0.50000  
Fiscal Year 2005
  July 8, 2005   July 14, 2005   $ 0.48750  
    March 16, 2005   April 14, 2005     0.46250  
    January 5, 2005   January 14, 2005     0.43750  
    October 7, 2004   October 15, 2004     0.41250  
 
 
(1) Special SCANA distribution — On June 20, 2006, the Board of Directors of ETP’s general partner declared a special distribution of $0.0325 per limited partner unit related to the proceeds we received in connection with the SCANA litigation settlement. This distribution was paid on July 14, 2006 to the holders of record of ETP’s common and Class F units as of the close of business on June 30, 2006. This special one-time payment was approved following a determination of the Litigation Committee of ETP’s general partner to distribute all the net distributable litigation proceeds we received in accordance with the partnership agreement. The special distribution also included a payment distribution of $3.6 million to the holder of ETP’s Class C units for that amount that would otherwise have been distributed to its general partner.
 
On September 25, 2007, ETP announced the declaration of a cash distribution for the fourth quarter ended August 31, 2007 of $0.825 per common unit, or $3.30 annually, an increase of $0.075 per common unit on an


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annualized basis. The distribution was paid on October 16, 2007 to unitholders of record at the close of business on October 5, 2007.
 
The total amount of distributions (all from Available Cash from ETP’s operating surplus) declared during the years ended August 31, 2007, 2006 and 2005 are as follows:
 
                         
    2007     2006     2005  
 
Limited Partners —
                       
Common Units
  $ 366,180     $ 248,237     $ 173,802  
Class C Units(1)
          3,599        
Class F Units
          3,232        
Class G Units
    40,598              
General Partners —
                       
2% Ownership
    12,701       6,981       4,390  
Incentive Distribution Rights
    203,069       81,722       28,847  
                         
    $ 622,548     $ 343,771     $ 207,039  
                         
 
 
(1) Special SCANA distribution — see discussion above.
 
New Accounting Standards
 
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109, or 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 to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We adopted this statement on September 1, 2007. We are continuing to evaluate the impact of FIN 48, but at this time we believe that the adoption of FIN 48 will not have a significant impact on our consolidated financial statements.
 
FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements, or FSP 00-19-2. FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5, Accounting for Contingencies, or SFAS No. 5. FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception,


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the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. We adopted this Staff Position on September 1, 2007 and the impact was not significant.
 
SFAS No. 154, Accounting Changes and Error Correction — a replacement of APB Opinion No. 20 and FASB Statement No. 3, or SFAS 154. In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Management adopted the provisions of SFAS 154 on September 1, 2006, with no material impact on our consolidated results of operations, cash flows or financial position.
 
SFAS No. 157, Fair Value Measurement, or SFAS 157. This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).
 
SFAS Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), or SFAS 158. Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. Management does not believe the adoption of the measurement provisions of this statement will have a material impact on our financial statements. We plan to adopt the measurement provisions of this statement when required during our calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).
 
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115, or SFAS 159. This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective, however, the amendment applies to all entities with available-for-sale and trading securities. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes the choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS 157 (discussed above). We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to


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adopt this statement when required at the start of our calendar year beginning January 1, 2008 (see Note 17 to our consolidated financial statements).
 
EITF Issue No. 04-05, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, or EITF 04-05. EITF 04-05 provides guidance in determining whether a general partner controls a limited partnership by determining the limited partners’ substantive ability to dissolve (liquidate) the limited partnership as well as assessing the substantive participating rights of the limited partners within the limited partnership. EITF 04-05 states that if the limited partners do not have substantive ability to dissolve (liquidate) or have substantive participating rights, the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. This EITF is effective in fiscal periods beginning after December 15, 2005. We believe that our consolidation of ETP, ETP GP LP and ETP LLC complies with the provisions of EITF 04-05.
 
SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108. In September 2006, the SEC provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB 108 on August 31, 2007. The adoption did not have a material impact on our consolidated financial statements.
 
Critical Accounting Policies and Estimates
 
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies and a discussion of new accounting pronouncements, see Note 3 to our consolidated financial statements.
 
Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities and accruals for and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. As is normal in the natural gas industry, our most current month’s financial results for our midstream and transportation and storage segments are estimated using volume estimates and market prices. Variances in these estimates, including variances in volume estimates, are inherent in our business. Actual results could differ from our estimates if the underlying assumptions prove to be incorrect, and such differences could be material.
 
Revenue Recognition.  Revenues for sales of natural gas, NGLs including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation.
 
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,


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compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
 
We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount, or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and processes natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
 
Our intrastate transportation and storage segment and interstate transportation segment results are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. The intrastate transportation and storage segment also generates its revenues and margin from the sale and marketing of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System.
 
Transwestern is subject to FERC regulations. As a result, FERC may require the refund of revenues collected during the pendency of a rate proceeding in a final order. Transwestern establishes reserves for these potential refunds, as appropriate. No such reserves were required at August 31, 2007.
 
We account for our trading activities under the provisions of EITF Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” or EITF 02-3, which requires revenue and costs related to energy trading contracts to be presented on a net basis in the income statement.
 
Regulatory Assets and Liabilities.  Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to Statement of Financial Accounting Standards No. 71 (As Amended), Accounting for the Effects of Certain Types of Regulation, or SFAS 71, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
 
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,” or SFAS 133, the gains and losses resulting from changes in the fair value of these contracts are recorded on a


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current basis on the statement of operations. In our retail propane business, we classify all gains and losses from these derivative contracts entered into for risk management purposes as liquids marketing revenue in the consolidated statement of operations. The gains and losses on the natural gas derivative contracts that are entered into for trading purposes are recognized in the midstream and transportation and storage revenue on a net basis in the consolidated statement of operations. The non-trading gains and losses for natural gas contracts are recorded as cost of products sold in the consolidated statement of operations. On our contracts that are designated as cash flow hedges in accordance with SFAS No. 133, the effective portion of the hedged gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the physical transaction settles. The ineffective portion of the gain or loss is reported in earnings immediately. We utilize published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. We also use the Black-Scholes valuation model to estimate the value of certain options. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “— Quantitative and Qualitative Disclosures about Market Risk”, for further discussion regarding our derivative activities.
 
Impairment of Long-Lived Assets and Goodwill.  Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with infinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
 
In order to test for recoverability, we must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas and propane supply, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other midstream companies, including major energy producers. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.
 
Property, Plant, and Equipment.  Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures also include capital expenditures made to connect additional wells to our systems in order to maintain or increase throughput on our existing assets. Growth or expansion capital expenditures are capital expenditures made to expand the existing operating capacity of our assets, whether through construction or acquisition. We treat repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as we incur them. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful life ranging from 3 to 80 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful live of our property, plant, and equipment.
 
Amortization of Intangible Assets.  For those intangible assets that do not have indefinite lives, we calculate amortization using the straight-line method over periods ranging from 2 to 15 years. We use amortization methods and determine asset values based on management’s best estimate using reasonable and supportable assumptions and projections. Changes in the amortization methods, asset values or estimated lives could have a material effect on our results of operations. We do not anticipate future changes in the estimated useful lives of our intangible assets.
 
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


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reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.
 
In order to determine fair value, management must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective. We have determined that we are obligated by contractual or regulatory requirements to remove assets or perform other remediation upon retirement of certain assets. However, the fair value of our asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. We will record an asset retirement obligation in the periods in which it can reasonably determine the settlement dates.
 
Legal Matters.  We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints.
 
For more information on our litigation and contingencies, see Note 10 to our consolidated financial statements incorporated by reference in this prospectus supplement.
 
Quantitative and Qualitative Disclosures About Market Risk
 
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risks related to interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.
 
Commodity Price Risk
 
We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell in our midstream and intrastate transportation and storage operations. We control the scope of risk management, marketing and trading activities through a comprehensive set of policies and procedures involving senior levels of management. The Audit Committee of our Board of Directors has oversight responsibilities for our risk management limits and policies. A Risk Oversight Committee, comprised of the Chief Executive Officer, Chief Financial Officer, Chief Administrative and Compliance Officer, Treasurer, President — Midstream, Controller of our midstream and intrastate transportation and storage operations, and Senior Vice President — Commercial Optimization of our midstream and transportation and storage operations, sets forth risk management policies and objectives. The Committee establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The trading activities are subject to the commodity risk management policy that includes risk management limits, including volume and stop-loss limits, to manage exposure to market risk. We do not engage in any derivative related activities in our interstate transportation segment.
 
In our retail propane business, the market price of propane is often subject to volatility changes as a result of supply or other market conditions over which we have no control. In the past, price changes have generally been passed along to our propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to us during periods of high demand, we will at times purchase significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price. The propane is then stored at both our customer service locations and in major storage facilities for future resale.


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Non-trading Activities
 
We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.
 
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when 1) sales volumes are less than expected, or 2) our counterparties fail to purchase the contracted quantities of natural gas or propane or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly protected against decreases in such prices on hedged transactions.
 
We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in prices. However, we are subject to counterparty risk for both the physical and financial contracts. We also utilize forward purchase contracts to acquire a portion of the propane that we resell to our customers, which allows us to manage our exposure to unfavorable changes in commodity prices and to assure adequate physical supply. We account for such physical contracts under the “normal purchases and sales exception” of SFAS 133.
 
In connection with the acquisition of the HPL System, we acquired certain physical forward contracts that contain embedded options that we have not designated as a normal purchase and sale nor were the contracts designated as hedges under SFAS 133. These contracts are marked to market, along with the financial options that offset them, and are recorded in the statement of operations and on our consolidated balance sheet as a component of price risk management assets and liabilities.
 
In our midstream and intrastate transportation and storage segments, we account for certain of our derivatives as cash flow hedges under SFAS 133. All derivatives are recognized on the balance sheet at fair value as price risk management assets and liabilities. The changes in the fair value of price risk management assets and liabilities that are designated, documented as cash flow hedges, and determined to be effective are recorded through other comprehensive income (loss). The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income (loss) and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. For those derivatives that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations.
 
We also attempt to maintain balanced positions in our midstream and intrastate transportation and storage segments to protect us from the volatility in the energy commodities markets. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results either favorably or unfavorably.
 
Trading Activities
 
We have a risk management policy that provides for our marketing and trading operations to assume limited market price risk. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain transactions and forward contracts are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis swaps and gas daily contracts. These instruments are within the guidelines of the risk management policy which has been approved by our Board of Directors. The trading activities are a complement to the producer services’ operations and are accounted for in net revenues on the consolidated statement of operations. We follow the applicable provisions of EITF Issue 02-3 which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the consolidated statement of operations as other revenue. Changes in the assets and liabilities from the trading activities result primarily from changes in the market prices, newly originated transactions, and the timing and


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settlement of contracts. Forward physical contracts associated with the trading activities are marked to market and included in revenue on our consolidated statement of operations because they do not meet “normal purchases and sales exception” of SFAS 133.
 
As a result of our trading activities and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and intrastate transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our Risk Management Committee, which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy.
 
Commodity-related Derivatives
 
Our commodity-related price risk management assets and liabilities as of August 31, 2007 were as follows:
 
                         
        Notional
           
        Volume
        Fair
 
    Commodity   MMBTU     Maturity   Value  
 
Mark to Market Derivatives
                       
(Non-Trading)
                       
Basis Swaps IFERC/NYMEX
  Gas     14,195,262     2007-2009   $ 5,551  
Swing Swaps IFERC
  Gas     7,282,500     2007-2008     (514 )
Fixed Swaps/Futures
  Gas     (590,000 )   2007-2009     1,298  
Forward Physical Contracts
  Gas     (6,437,413 )   2007-2008     343  
Options
  Gas     (976,000 )   2007-2008     (346 )
Forward/Swaps — in Gallons
  Propane/Ethane     8,862,000     2007-2008     777  
(Trading)
                       
Basis Swaps IFERC/NYMEX
  Gas     (4,922,500 )   2007-2008   $ 2,390  
Swing Swaps IFERC
  Gas     (21,250,000 )   2007     (33 )
Forward Physical Contracts
  Gas         2007     323  
Fixed Swaps/Futures
  Gas     (10,275,000 )   2007     (177 )
Cash Flow Hedging Derivatives
                       
(Non-Trading)
                       
Basis Swaps IFERC/NYMEX
  Gas     (10,962,500 )   2007-2008   $ 124  
Fixed Swaps/Futures
  Gas     (11,230,000 )   2007-2009     23,078  
 
Credit Risk
 
We maintain credit policies with regard to our counterparties that we believe significantly minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.
 
Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies, or LDCs. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.


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Sensitivity analysis
 
The table below summarizes our commodity-related financial derivative instruments and fair values as of August 31, 2007. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.
 
                         
    Notional
          Effect of
 
    Volume
          Hypothetical
 
    MMBTU     Fair Value     10% Change  
 
Non-Trading Derivatives
                       
Fixed Swaps/Futures
    (11,820,000 )   $ 24,376     $ 10,929  
Basis Swaps IFERC/NYMEX
    3,232,762       5,675       1,091  
Swing Swaps IFERC
    7,282,500       (514 )     467  
Options
    (976,000 )     (346 )     190  
Forward Physical Contracts’
    (6,437,413 )     343       3,442  
Propane Forwards/Swaps (in Gallons)
    8,862,000       777       3,495  
Trading Derivatives
                       
Swing Swaps IFERC
    (21,250,000 )     (33 )     1,737  
Basic Swaps IFERC/NYMEX
    (4,922,500 )     2,390       17  
Forward Physical Contracts
          323       2,980  
Fixed Swaps/Futures
    (10,275,000 )     (177 )     5,579  
 
The table below summarizes our positions and values as of August 31, 2006. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.
 
                         
    Notional
          Effect of
 
    Volume
          Hypothetical
 
    MMBTU     Fair Value     10% Change  
 
Non-Trading Derivatives
                       
Fixed Swaps/Futures
    (34,265,000 )   $ 1,873     $ 42,615  
Basis Swaps IFERC/NYMEX
    (873,860 )     (9,234 )     1,594  
Swing Swaps IFERC
    (37,220,448 )     2,618       514  
Options
    (1,046,000 )     21,653       5,189  
Forward Physical Contracts
    (7,986,000 )     (21,653 )     5,189  
Propane Forwards/Swaps (in Gallons)
    24,066,000       199       2,766  
Trading Derivatives
                       
Swing Swaps IFERC
          (31 )     205  
Basic Swaps IFERC/NYMEX
    (2,572,500 )     21,995       701  
Forward Physical Contracts
    (455,000 )     (68 )     75  
 
The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10 percent change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or in accumulated other comprehensive income. In the event of an actual 10 percent change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10 percent due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.


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Interest Rate Risk
 
We are exposed to market risk for changes in interest rates, primarily as a result of our variable rate debt and, in particular, our bank credit facilities. To the extent interest rates increase, our interest expense for our revolving credit facilities will also increase. At August 31, 2007, we had a total of $2.541 billion of variable rate debt outstanding and we have $1.625 billion of interest rate swaps where we pay fixed and receive floating LIBOR. Interest swaps with a notional amount of $700.0 million are designated as hedges and changes in fair value are recorded in accumulated other comprehensive income. Interest swaps with a notional amount of $925.0 million have their changes in fair value recorded in other income on the consolidated statement of operations. A hypothetical change of 100 basis points in the underlying interest rate and a corresponding parallel shift in the LIBOR yield curve would have an effect of $26.4 million in interest expense and other income, in the aggregate, on an annual basis.
 
We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt. For further information, see Note 11 to our consolidated financial statements incorporated by reference in this prospectus supplement.


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MANAGEMENT
 
Partnership Management
 
LE GP LLC 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 president, to appoint a replacement. All of the current directors of our general partner also serve as directors of the general partner of ETP.
 
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 of our general partner as of October 16, 2007. Executive officers and directors are elected for indefinite terms.
 
             
Name
 
Age
 
Position with Our General Partner
 
John W. McReynolds
  56   Director, President and Chief Financial Officer
Kelcy L. Warren
  51   Director and Chairman of the Board
Ray C. Davis
  65   Director
Kenneth A. Hersh
  44   Director
David R. Albin
  48   Director
K. Rick Turner
  49   Director
Bill W. Byrne
  77   Director
Paul E. Glaske
  74   Director
John D. Harkey, Jr
  47   Director
 
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
 
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.
 
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 initial public offering. On August 15, 2007, Mr. Warren became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETP. Mr. Warren had previously served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETP 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 Chief Executive Officer of the general partner of ETC OLP. 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


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Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.
 
Ray C. Davis.  Mr. Davis served as Co-Chairman of the Board of Directors of our general partner, LE GP, LLC, effective upon the closing of our initial public offering until his retirement effective August 15, 2007. Mr. Davis also served as Co-Chief Executive Officer and Co-Chairman of the Board of Directors of the general partner of ETP since the combination of the midstream and transportation operations of ETC OLP and the retail propane operations of Heritage in January 2004 until his retirement from these positions effective August 15, 2007. Mr. Davis also served 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 held since their formation in 2002. Mr. Davis now serves as a director of the general partners of ETP and ETE. 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 32 years of business experience in the energy industry. Mr. Davis became a venture partner of Natural Gas Partners, L.L.C. in September 2007.
 
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 and as a director of the general partner of Eagle Rock Energy Partners, L.P. 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.
 
David R. Albin.  Mr. Albin is a managing partner of the Natural Gas Partners private equity funds, 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.
 
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 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.
 
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, or 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


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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.


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SELLING UNITHOLDERS
 
The following table sets forth information concerning the ownership of our common units by the selling unitholders. As of November 5, 2007, there were 222,829,956 of our common units outstanding. The percentages indicated below represent the selling unitholders’ ownership of our common units.
 
                                         
    Common Units
          Common Units
 
    Beneficially
          Beneficially
 
    Owned Immediately
          Owned Immediately
 
    Prior to this Offering     Common
    after this Offering(1)  
    Common
          Units to be
    Common
       
Name of Selling Unitholder
  Units     Percent     Offered     Units     Percent  
 
Kellen Holdings, LLC(2)
    7,437,077       3.34 %     6,467,023       970,054             *
PH Investments, LLC(3)
    4,383,071       1.97 %     869,565       3,513,506       1.58 %
                                         
Totals
    11,820,148             7,336,588       4,483,560        
                                         
 
 
* Less than 1%.
(1) Assumes that the underwriters do not exercise their over-allotment option. If the underwriters exercise their over-allotment option in full, Kellen Holdings, LLC will sell an additional 970,054 common units and PH Investments, LLC will sell an additional 130,435 common units.
(2) Kellen Holdings, LLC, a Delaware limited liability company, is a direct subsidiary of Liberty Energy Holdings, LLC, a Delaware LLC, or LEH, and is an indirect subsidiary of Liberty Mutual Holding Company Inc., a Massachusetts mutual holding company. Liberty Mutual Holding Company Inc. is the ultimate controlling person of Kellen Holdings, LLC. Liberty Mutual Holding Company Inc. is a mutual holding company wherein its members are entitled to vote at meetings of the company. No such member is entitled to cast 10% or more of the votes. Liberty Mutual Holding Company Inc. has issued no voting securities.
(3) PH Investments LLC is an investment vehicle which is managed by Amos B. Hostetter, Jr. Amos B. Hostetter, Jr. is the sole managing member of PH Investments, LLC. Amos B. Hostetter is the only person deemed to have beneficial ownership of the securities.


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MATERIAL TAX CONSIDERATIONS
 
The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. Although this section updates and adds information related to certain tax considerations, it should be read in conjunction with “Material Tax Consequences” in the accompanying base prospectus, which provides a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of common units.
 
All prospective unitholders are encouraged to consult with their own tax advisor about the federal, state, local and foreign tax consequences particular to their own circumstances. In particular, ownership of common units by tax-exempt entities, including employee benefit plans and IRAs, and foreign investors raises issues unique to such persons. Such investors should read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” in the accompanying base prospectus.
 
Partnership Status
 
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. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids, certain related hedging activities, and our allocable share of income ETP’s income from these sources. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that approximately 8% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. For a discussion related to the opinion of Vinson & Elkins L.L.P. and the importance of our status as a partnership, please read “Material Tax Consequences — Partnership Status” in the accompanying base prospectus.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Specifically, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.


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Ratio of Taxable Income to Distributions
 
We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 10% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from ETP’s operations will approximate the amount required to make its distributions on all units and other assumptions with respect to our and ETP’s capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.


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UNDERWRITING
 
Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus supplement, the underwriters named below, for whom Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc. and UBS Securities LLC are acting as representatives, have severally agreed to purchase, and the selling unitholders have agreed to sell to them, severally, the number of common units indicated below:
 
         
    Number of
 
Underwriter
  Common Units  
 
Morgan Stanley & Co. Incorporated
    2,261,870  
Citigroup Global Markets Inc. 
    2,261,870  
UBS Securities LLC
    2,261,870  
Credit Suisse Securities (USA) LLC
    550,978  
         
Total
    7,336,588  
         
 
The underwriters and the representatives are collectively referred to as the “underwriters” and the “representatives,” respectively. The underwriters are offering the common units subject to their acceptance of the common units from the selling unitholders and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the common units offered by this prospectus supplement are subject to the approval of certain legal matters by their counsel and to certain other conditions. The underwriters are obligated to take and pay for all of the common units offered by this prospectus supplement if any such common units are taken. However, the underwriters are not required to take or pay for the common units covered by the underwriters over-allotment option described below.
 
The underwriters initially propose to offer part of the common units directly to the public at the public offering price listed on the cover page of this prospectus supplement and part to certain dealers at a price that represents a concession not in excess of $0.76 per common unit under the public offering price. After the initial offering of the common units in this offering, the offering price and other selling terms may from time to time be varied by the representatives.
 
The selling unitholders have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to an aggregate of 1,100,489 additional common units at the public offering price listed on the cover page of this prospectus supplement, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of the common units offered by this prospectus supplement. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase about the same percentage of the additional common units as the number listed next to the underwriter’s name in the preceding table bears to the total number of common units listed next to the names of all underwriters in the preceding table. If the underwriters’ option is exercised in full, the total price to the public would be $267,455,341, the total underwriters discounts and commissions would be $10,698,214 and total proceeds to the selling unitholders would be $256,757,127.
 
                         
          Total  
          Without
    With
 
          Over-Allotment
    Over-Allotment
 
    Per Unit     Option     Option  
 
Public offering price
  $ 31.70     $ 232,569,840     $ 267,455,341  
Underwriting discounts and commissions
  $ 1.268     $ 9,302,794     $ 10,698,214  
Proceeds, before expenses, to Selling Unitholders
  $ 30.432     $ 223,267,046     $ 256,757,127  
 
We estimate that our out of pocket expenses for this offering, excluding underwriter discounts and commissions, will be approximately $275,000.


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Each of ETE, the selling unitholders and the directors and executive officers of our general partner have agreed that, without the prior written consent of Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc. and UBS Securities LLC on behalf of the underwriters, it will not, during the period ending 90 days after the date of this prospectus supplement:
 
  •  offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of directly or indirectly, any common units or any securities convertible into or exercisable or exchangeable for common units or file any registration statement under the Securities Act of 1933 with respect to the foregoing;
 
  •  or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units,
 
whether any transaction described above is to be settled by delivery of common units or such other securities, in cash or otherwise.
 
The restrictions described in this paragraph do not apply to, among other things:
 
  •  the sale of units to the underwriters pursuant to the underwriting agreement;
 
  •  the issuance by us of common units upon the exercise of an option or a warrant or the conversion of a security outstanding on the date of this prospectus supplement of which the underwriters have been advised in writing;
 
  •  the filing of any registration statements by us for the benefit of any unitholder pursuant to any registration obligations existing on the date hereof; or
 
  •  transactions by any person other than us relating to common units or other securities acquired in open market transactions after the completion of the offering of the units.
 
In order to facilitate the offering of the common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common units. Specifically, the underwriters may sell more units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is “covered” if the short position is no greater than the number of units available for purchase by the underwriters under the over-allotment option. The underwriters can close out a covered short sale by exercising the over-allotment option or purchasing units in the open market. In determining the source of units to close out a covered short sale, the underwriters will consider, among other things, the open market price of units compared to the price available under the over-allotment option. The underwriters may also sell units in excess of the over-allotment option, creating a “naked” short position. The underwriters must close out any naked short position by purchasing units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. As an additional means of facilitating the offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of the common units. These activities may raise or maintain the market price of the common units above independent market levels or prevent or retard a decline in the market price of our common units. The underwriters are not required to engage in these activities and may end any of these activities at any time. Prior to purchasing the common units being offered pursuant to this prospectus supplement, on November 6, 2007 and November 7, 2007, one of the underwriters purchased, on behalf of the syndicate, 206,700 common units at an average price of $31.7316 per unit in stabilizing transactions.
 
The underwriters and their affiliates may, from time to time, perform investment banking and commercial banking services for us and our affiliates in the ordinary course of their business.
 
We, the selling unitholders and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act of 1933.
 
Because the National Association of Securities Dealers, Inc. views the common units offered by this prospectus supplement and the accompanying base prospectus as interests in a direct participation program,


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the offering is being made in compliance with Rule 2810 of the Conduct Rules of the National Association of Securities Dealers, Inc.
 
A prospectus in electronic format may be made available on the websites maintained by the underwriters or their affiliates. The underwriters may agree to allocate a number of common units for sale to their online brokerage account holders. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.
 
Other than the prospectus in electronic format, the information on the underwriters’ web sites and any information contained in any other web sites maintained by the underwriters is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or the underwriters in their capacity as underwriters and should not be relied upon by investors.
 
Wachovia Bank, National Association, Bank of America, N.A., BNP Paribas, Citicorp North America, Inc., The Royal Bank of Scotland plc, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, UBS Loan Finance LLC, UBS Securities LLC, Fortis Capital Corp., SunTrust Bank, Royal Bank of Canada, U.S. Bank National Association, West CB AG, New York Branch, Amegy Bank National Association, Compass Bank, Malayon Banking Berhad, New York Branch, Raymond James Bank, FSB and Regions Bank are lenders under our secured revolving credit facility.
 
This prospectus supplement and the accompanying base prospectus may be used by Morgan Stanley & Co. Incorporated in connection with offers and sales of the common units in certain agented brokers’ transactions; however, Morgan Stanley & Co. Incorporated is not obligated to engage in such agented brokers’ transactions and may discontinue such activities without notice at any time.
 
Affiliates of Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC are lenders and agents under certain of ETP’s credit facilities for which they receive interest and fees as provided in the credit agreements related to these facilities. In addition, an affiliate of Credit Suisse Securities (USA) LLC acted as ETP’s financial advisor with respect to ETP’s acquisition of Transwestern in 2006 for which this affiliate was paid a financial advisor fee.
 
Credit Suisse Securities (USA) LLC served as joint book-running manager and UBS Securities LLC served as a co-manager in connection with ETP’s October 2006 senior notes offering. Credit Suisse Securities (USA) LLC and UBS Securities LLC received customary compensation for such services.


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LEGAL MATTERS
 
The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the selling unitholders by Hunton & Williams LLP, Dallas, Texas and the underwriters by Andrews Kurth LLP, Houston, Texas.
 
EXPERTS
 
The consolidated financial statements and the effectiveness of internal control over financial reporting of Energy Transfer Equity, L.P. and the consolidated balance sheet of LE GP, LLC all incorporated in this prospectus supplement by reference from Energy Transfer Equity, L.P.’s Annual Report on form 10-K for the year ended August 31, 2007 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said reports.
 
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
 
This prospectus supplement contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
 
  •  the amount of natural gas transported on ETP’s pipelines and gathering systems;
 
  •  the level of throughput in ETP’s natural gas processing and treating facilities;
 
  •  the fees ETP charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;
 
  •  the prices and market demand for, and the relationship between, natural gas and NGLs;
 
  •  energy prices generally;
 
  •  the prices of natural gas and propane compared to the price of alternative and competing fuels;
 
  •  the general level of petroleum product demand and the availability and price of propane supplies;
 
  •  the level of domestic oil, propane and natural gas production;
 
  •  the availability of imported oil and natural gas;
 
  •  the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the political and economic stability of petroleum producing nations;
 
  •  the effect of weather conditions on demand for oil, natural gas and propane;
 
  •  availability of local, intrastate and interstate transportation systems;
 
  •  the continued ability to find and contract for new sources of natural gas supply;


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  •  availability and marketing of competitive fuels;
 
  •  the impact of energy conservation efforts;
 
  •  energy efficiencies and technological trends;
 
  •  governmental regulation and taxation;
 
  •  changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;
 
  •  hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;
 
  •  the maturity of the propane industry and competition from other propane distributors;
 
  •  competition from other midstream companies, interstate pipeline companies and propane distribution companies;
 
  •  loss of key personnel;
 
  •  loss of key natural gas producers or the providers of fractionation services;
 
  •  reductions in the capacity or allocations of third party pipelines that connect with ETP’s pipelines and facilities;
 
  •  the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments;
 
  •  the nonpayment or nonperformance by ETP’s customers;
 
  •  regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;
 
  •  risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities;
 
  •  the availability and cost of capital and ETP’s ability to access certain capital sources;
 
  •  the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses;
 
  •  changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
 
  •  the costs and effects of legal and administrative proceedings.
 
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus
 
WHERE YOU CAN FIND MORE INFORMATION
 
We file annual, quarterly, and current reports, proxy statements and other information with the SEC. You can read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You can obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains information we file electronically with the SEC, which you can access over the Internet at http://www.sec.gov.
 
Our home page is located at http://www.energytransfer.com. Our annual reports on Form 10-K, our quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC are available free of charge through our web site as soon as reasonably practicable after those reports or filings are electronically filed or


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furnished to the SEC. Information on our web site or any other web site is not incorporated by reference in this prospectus and does not constitute a part of this prospectus.
 
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
 
We are incorporating by reference in this prospectus information we file with the SEC, which means that we are disclosing important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus, and later information that we file with the SEC automatically will update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities and Exchange Act of 1934, excluding any information in those documents that is deemed by the rules of the SEC to be furnished not filed, until we close this offering:
 
  •  our annual report on Form 10-K for the year ended August 31, 2007;
 
  •  our current report on Form 8-K filed with the SEC on November 2, 2007; and
 
  •  the description of our common units contained in our Registration Statement on From 8-A filed with the SEC on January 31, 2006.
 
You may request a copy of these filings, which we will provide to you at no cost, by writing or telephoning us at the following address and telephone number:
 
Energy Transfer Equity, L.P.
3738 Oak Lawn Avenue
Dallas, Texas 75219
Attention: Sonia Aube
Telephone: (214) 981-0700


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Prospectus
 
 
66,625,100
 
Energy Transfer Equity, L.P.
 
 
 
 
Common Units
 
 
 
 
The securities to be offered and sold using this prospectus are currently issued and outstanding common units representing limited partner interests in us. These common units may be offered and sold by the selling unitholders named in this prospectus or in any supplement to this prospectus from time to time in accordance with the provisions set forth under “Plan of Distribution.”
 
The selling unitholders may sell the common units offered by this prospectus from time to time on any exchange on which the common units are listed on terms to be negotiated with buyers. It may also sell the common units in private sales or through dealers or agents. The selling unitholders may sell the common units at prevailing market prices or at prices negotiated with buyers. The selling unitholders will be responsible for any commissions due to brokers, dealers or agents. We will be responsible for all other offering expenses. We will not receive any of the proceeds from the sale by the selling unitholders of the common units offered by this prospectus.
 
You should carefully read this prospectus and any supplement before you invest. You also should read the documents we have referred you to in the “Where You Can Find More Information” section of this prospectus for information on us and our financial statements. This prospectus may not be used to consummate sales of securities unless accompanied by a prospectus supplement.
 
Our common units are listed on the New York Stock Exchange under the symbol “ETE.”
 
 
 
 
Each time we sell securities we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read this prospectus and any prospectus supplement carefully before you invest. You should also read the documents we have referred you to in the “Where You Can Find More Information” section of this prospectus for information on us and for our financial statements.
 
Investing in our securities involves risks. Limited partnerships are inherently different from corporations. You should carefully consider the risk factors beginning on page 4 of this prospectus and in the applicable prospectus supplement before you make an investment in our securities.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
 
 
 
 
The date of this prospectus is October 23, 2007.


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In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with any other information. If anyone provides you with different or inconsistent information, you should not rely on it.
 
You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. You should not assume that the information contained in the documents incorporated by reference in this prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.


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ABOUT THIS PROSPECTUS
 
This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or SEC, using a “shelf” registration process. Under this shelf process the selling unitholders named in this prospectus or in any supplement to this prospectus may sell the common units described in this prospectus in one or more offerings. This prospectus provides you with a general description of the common units the selling unitholders may offer. Each time it sells common units, the selling unitholders will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read both the prospectus and the prospectus supplement relating to the common units offered to you together with the additional information described under the heading “Where You Can Find More Information.”
 
All references in this prospectus to “we,” “us,” “Energy Transfer Equity” and “our” refer to Energy Transfer Equity, L.P. and its subsidiaries, Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P. All references in this prospectus to “our general partner” refer to LE GP, LLC. All references in this prospectus to “Energy Transfer Partners GP” or “ETP GP” refer to Energy Transfer Partners GP, L.P. All references in this prospectus to “Energy Transfer Partners” or “ETP” refer to Energy Transfer Partners, L.P. and its wholly owned subsidiaries and predecessors.
 
ENERGY TRANSFER EQUITY, L.P.
 
We are a publicly traded limited partnership. 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 initial public offering of 24,150,000 common units in February 2006. Our only cash generating assets are our direct and indirect investments in limited partner and general partner interests in our subsidiary, Energy Transfer Partners, L.P. Our direct and indirect ownership of ETP consists of approximately 62.5 million common units, the 2% general partner interests (through Energy Transfer Partners GP, L.P., ETP’s general partner and one of our subsidiaries) and 100% of the incentive distribution rights.
 
Our principal executive offices are located at 3738 Oak Lawn Avenue, Dallas, Texas 75219, and our telephone number at that location is (214) 981-0700.
 
ENERGY TRANSFER PARTNERS, L.P.
 
ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, interstate transportation pipelines, natural gas treating and processing assets located in Texas, New Mexico, Arizona, Oklahoma, Louisiana, Utah and Colorado and three natural gas storage facilities located in Texas. These assets include approximately 14,000 miles of intrastate pipeline in service, with an additional 500 miles of intrastate pipeline under construction, and 2,400 miles of interstate pipelines. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.
 
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
 
This prospectus contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results


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may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
 
  •  the amount of natural gas transported on ETP’s pipelines and gathering systems;
 
  •  the level of throughput in ETP’s natural gas processing and treating facilities;
 
  •  the fees ETP charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;
 
  •  the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs;
 
  •  energy prices generally;
 
  •  the prices of natural gas and propane compared to the price of alternative and competing fuels;
 
  •  the general level of petroleum product demand and the availability and price of propane supplies;
 
  •  the level of domestic oil, propane and natural gas production;
 
  •  the availability of imported oil and natural gas;
 
  •  the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the political and economic stability of petroleum producing nations;
 
  •  the effect of weather conditions on demand for oil, natural gas and propane;
 
  •  availability of local, intrastate and interstate transportation systems;
 
  •  the continued ability to find and contract for new sources of natural gas supply;
 
  •  availability and marketing of competitive fuels;
 
  •  the impact of energy conservation efforts;
 
  •  energy efficiencies and technological trends;
 
  •  of governmental regulation and taxation;
 
  •  changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;
 
  •  hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;
 
  •  the maturity of the propane industry and competition from other propane distributors;
 
  •  competition from other midstream companies, interstate pipeline companies and propane distribution companies;
 
  •  loss of key personnel;
 
  •  loss of key natural gas producers or the providers of fractionation services;
 
  •  reductions in the capacity or allocations of third party pipelines that connect with ETP’s pipelines and facilities;
 
  •  the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments;
 
  •  the nonpayment or nonperformance by ETP’s customers;


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  •  regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;
 
  •  risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities;
 
  •  the availability and cost of capital and ETP’s ability to access certain capital sources;
 
  •  the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses;
 
  •  changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
 
  •  the costs and effects of legal and administrative proceedings.
 
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus.


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RISK FACTORS
 
An investment in our securities involves a high degree of risk. You should carefully consider the following risk factors, together with all of the other information included in, or incorporated by reference into, this report in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.
 
Risks Inherent in an Investment in Us
 
Our only assets are our partnership interests, including the incentive distribution rights, in ETP and, therefore, our cash flow is dependent upon the ability of ETP to make distributions in respect of those partnership interests.
 
The amount of cash that ETP can distribute to its partners, including us, each quarter depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:
 
  •  the amount of natural gas transported in ETP’s pipelines and gathering systems;
 
  •  the level of throughput in its processing and treating operations;
 
  •  the fees it charges and the margins it realizes for its gathering, treating, processing, storage and transportation services;
 
  •  the price of natural gas;
 
  •  the relationship between natural gas and NGL prices;
 
  •  the weather in its operating areas;
 
  •  the cost of the propane it buys for resale and the prices it receives for its propane;
 
  •  the level of competition from other midstream companies, interstate pipeline companies, propane companies and other energy providers;
 
  •  the level of its operating costs;
 
  •  prevailing economic conditions; and
 
  •  the level of ETP’s hedging activities.
 
In addition, the actual amount of cash that ETP will have available for distribution will also depend on other factors, such as:
 
  •  the level of capital expenditures it makes;
 
  •  the level of non-operating costs related to litigation and regulatory compliance matters;
 
  •  the cost of acquisitions, if any;
 
  •  the levels of any margin calls that result from changes in commodity prices;
 
  •  its debt service requirements;
 
  •  fluctuations in its working capital needs;
 
  •  its ability to make working capital borrowings under its credit facilities to make distributions;
 
  •  its ability to access capital markets;
 
  •  restrictions on distributions contained in its debt agreements; and
 
  •  the amount, if any, of cash reserves established by its general partner in its discretion for the proper conduct of ETP’s business.
 
Because of these factors, we cannot guarantee that ETP will have sufficient available cash to pay a specific level of cash distributions to its partners.
 
Furthermore, you should be aware that the amount of cash that ETP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and


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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” for a discussion of further risks affecting ETP’s ability to generate distributable cash flow.
 
We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.
 
The source of our earnings and cash flow is cash distributions from ETP. Therefore, the amount of distributions we are currently able to make to our unitholders may fluctuate based on the level of distributions ETP makes to its partners. ETP may not be able to continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if ETP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP to us.
 
Our ability to distribute cash received from ETP to our unitholders is limited by a number of factors, including:
 
  •  interest expense and principal payments on our indebtedness;
 
  •  restrictions on distributions contained in any current or future debt agreements;
 
  •  our general and administrative expenses;
 
  •  expenses of our subsidiaries other than ETP, including tax liabilities of our corporate subsidiaries, if any;
 
  •  capital contributions to maintain our 2% general partner interest in ETP as required by the partnership agreement of ETP upon the issuance of additional partnership securities by ETP; and
 
  •  reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.
 
We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.
 
The general partner is not elected by the unitholders and cannot be removed without its consent.
 
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner.
 
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units. Because affiliates of our general partner (including Enterprise GP Holdings L.P.) own approximately 122.6 million common units, representing 54.8% of our outstanding common units, it will be particularly difficult for our general partner to be removed without the consent of such affiliates. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
 
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


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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 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 May 31, 2007, we had approximately $5.0 billion of consolidated debt outstanding. Our level of indebtedness affects our operations in several ways, including, among other things:
 
  •  a significant portion of our and ETP’s cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
 
  •  covenants contained in our and ETP’s existing debt arrangements require us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our and ETP’s business;
 
  •  our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
 
  •  we may be at a competitive disadvantage relative to similar companies that have less debt;
 
  •  we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
 
  •  failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt and to pay distributions. We are required to measure these financial tests and covenants quarterly and, as of May 31, 2007, we were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under our existing credit agreements.
 
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
 
In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of May 31, 2007, we had approximately $5.0 billion of consolidated debt, of which approximately


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$4.1 billion was at fixed interest rates and approximately $0.9 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 our general partner may be factors in credit evaluations of us as a master limited partnership. This is because our general partner can exercise significant influence over our business activities, including our cash distributions and, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.
 
We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
 
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the common units, without the approval of our unitholders. The issuance of additional common units or other equity securities by us will have the following effects:
 
  •  our unitholders’ current proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each common unit or partnership security may decrease;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding common unit may be diminished; and
 
  •  the market price of our common units may decline.
 
In addition, ETP may sell an unlimited number of limited partner interests without the consent of its unitholders which will dilute existing interests of its unitholders, including us. The issuance of additional common units or other equity securities by ETP will have essentially the same effects as detailed above.
 
The market price of our common units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing unitholders.
 
Sales by any of our existing unitholders of a substantial number of our units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.
 
Control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner to sell or transfer all or part of their ownership interest in our general partner to a third party. The new owner or owners of our general partner


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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 Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Mackie McCrea, President of Midstream Operations and R.C. Mills, President of Propane Operations. Mr. Warren has been integral to the success of ETP’s midstream and transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing his leadership could make it more difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
 
ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
 
An increase in interest rates may cause the market price of our units to decline.
 
Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline.
 
Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under limited circumstances.
 
As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions in which we do business.
 
In some of the jurisdictions in which we do business, the applicable statutes do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the


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partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  your right to act with other unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.
 
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 SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.
 
If Energy Transfer Partners GP withdraws or is removed as ETP’s general partner, then we would lose control over the management and affairs of Energy Transfer Partners, the risk that we would be deemed an investment company under the Investment Company Act of 1940 would be exacerbated and our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP could be cashed out or converted into ETP common units at an unattractive valuation.
 
Under the terms of ETP’s partnership agreement, ETP GP will be deemed to have withdrawn as general partner if, among other things, it:
 
  •  voluntarily withdraws from the partnership by giving notice to the other partners;
 
  •  transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s partnership agreement;
 
  •  makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or
 
  •  dissolves itself under Delaware law without reinstatement within the requisite period.
 
In addition, ETP GP can be removed as ETP’s general partner if that removal is approved by unitholders holding at least 662/3% of ETP’s outstanding units (including units held by ETP GP and its affiliates).
 
If ETP GP withdraws from being ETP’s general partner in compliance with ETP’s partnership agreement or is removed from being ETP’s general partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor general partner to purchase its general partner interests, incentive distribution rights and limited partner interests in ETP for fair market value. If ETP GP withdraws from being ETP’s general partner in violation of ETP’s partnership agreement or is removed from being ETP’s general partner in circumstances where a court enters a judgment


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that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s general partner, and the successor general partner does not exercise its option to purchase the general partner interests, incentive distribution rights and limited partner interests held by ETP GP in ETP for fair market value, then the general partner interests and incentive distribution rights held by ETP GP in ETP could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP would lose control over the management and affairs of ETP, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act of 1940. In addition, our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP, to which a significant portion of the value of our common units is currently attributable, could be cashed out or converted into ETP common units at an unattractive valuation.
 
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 May 31, 2007, we owned approximately 62.5 million common units of ETP. If we were to sell and/or distribute any ETP common units to the holders of our equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of ETP’s outstanding common units and our receipt of distributions.
 
Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to our unitholders.
 
Prior to making any distributions to our unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.
 
In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our unitholders and cause the value of our common units to decline.
 
An impairment of goodwill and intangible assets could reduce our earnings.
 
At May 31, 2007, our consolidated balance sheet reflected $746 million of goodwill and $432 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,


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we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.
 
Risks Related to Conflicts of Interest
 
Although we control ETP through our ownership of its general partner, ETP’s general partner owes fiduciary duties to ETP and ETP’s unitholders, which may conflict with our interests.
 
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including ETP’s general partner, on the one hand, and ETP and its limited partners, on the other hand. The directors and officers of ETP’s general partner have fiduciary duties to manage ETP in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage ETP in a manner beneficial to ETP and its limited partners. The board of directors of ETP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
 
For example, conflicts of interest may arise in the following situations:
 
  •  the allocation of shared overhead expenses to ETP and us;
 
  •  the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand;
 
  •  the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business;
 
  •  the determination of whether to make borrowings under ETP’s revolving working capital facility to pay distributions to ETP’s partners; and
 
  •  any decision we make in the future to engage in business activities independent of ETP.
 
The fiduciary duties of our general partner’s officers and directors may conflict with those of ETP’s general partner.
 
Conflicts of interest may arise because of the relationships between ETP’s general partner, ETP and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner’s directors are also directors and officers of ETP’s general partner, and have fiduciary duties to manage the business of ETP in a manner beneficial to ETP and ETP’s unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
 
The risk of competition with affiliates of our general partner has increased.
 
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our Partnership Agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. On May 7, 2007, Enterprise GP Holdings L.P. acquired a 34.9% non-controlling equity interest in our general partner. Enterprise GP Holdings L.P. and its subsidiaries are a North American midstream energy business. As a result, there is greater risk that competition with affiliates of our general partner could occur, which could adversely impact our results of operations and cash available for distribution.
 
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own


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interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:
 
  •  Our general partner is allowed to take into account the interests of parties other than us, including ETP and its affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to our unitholders.
 
  •  Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
 
  •  Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.
 
  •  Our general partner determines which costs it and its affiliates have incurred are reimbursable by us.
 
  •  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
 
  •  Our general partner controls the enforcement of obligations owed to us by it and its affiliates.
 
  •  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
 
  •  provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
 
In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.


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Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of May 31, 2007, affiliates of our general partner, excluding Enterprise GP Holdings L.P., own approximately 37.4% of our common units.
 
We own an interstate pipeline that is subject to rate regulation by the Federal Energy Regulatory Commission and, in the event that 15% or more of our outstanding common units, in the aggregate, are held by persons who are not eligible holders, common units held by persons who are not eligible holders will be subject to the possibility of redemption at the then-current market price.
 
We own an interstate pipeline that is subject to rate regulation of the Federal Energy Regulatory Commission, or FERC, and as a result our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are Eligible Holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s rate base upon which tariffs may be established under FERC rate-making policies applicable to entities that pass-through their taxable income to their owners. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented and 15% or more of our outstanding common units are held by persons who are not Eligible Holders, we will have the right to redeem the units held by persons who are not Eligible Holders at the then-current market price. The redemption price would be paid in cash or by delivery of a promissory note, as determined by our general partner.
 
ETP may issue additional ETP units, which may increase the risk that ETP will not have sufficient Available Cash to maintain or increase its per unit distribution level.
 
ETP has wide latitude to issue additional units on terms and conditions established by its general partner. The payment of distributions on those additional units may increase the risk that ETP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders.
 
The issuance of additional common units or other equity securities of equal rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in ETP will decrease;
 
  •  the amount of cash available for distribution on each common unit may decrease; and
 
  •  the market price of our common units may decline.
 
Furthermore, our partnership agreement does not give our unitholders the right to approve our issuance of equity securities.
 
Risks Related to Energy Transfer Partners’ Business
 
Since our cash flows consist exclusively of distributions from ETP, risks to ETP’s business are also risks to us. We have set forth below risks to ETP’s business, the occurrence of which could have a negative impact on ETP’s financial performance and decrease the amount of cash it is able to distribute to us, thereby impacting the amount of cash that we are able to distribute to our unitholders.


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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, the North Texas System, and at ETP’s Houston Pipe Line 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 and North 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 the nine months ended May 31, 2007, the NYMEX settlement price for the prompt month contract ranged from a high of $8.87 per million British thermal units, or MMBtu, to a low of $4.20 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during the nine months ended May 31, 2007 ranged from a high of approximately $1.08 per gallon to a low of approximately $0.83 per gallon.
 
ETP’s average realized natural gas sales prices for the nine months ended May 31, 2007 were lower than ETP’s historical realized natural gas prices. For example, ETP’s average realized natural gas price decreased $1.88, or 24%, from $8.00 per MMBtu for the year ended August 31, 2006 to $6.12 per MMBtu for the nine months ended May 31, 2007. On August 14, 2007, the NYMEX settlement price for September 2007 natural gas deliveries was $6.94 per MMBtu, which was 13.4% higher than ETP’s average natural gas price for the nine months ended May 31, 2007. 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 Pipe Line 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.


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The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:
 
  •  the impact of weather on the demand for oil and natural gas;
 
  •  the level of domestic oil and natural gas production;
 
  •  the availability of imported oil and natural gas;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the availability of local, intrastate and interstate transportation systems;
 
  •  the price, availability and marketing of competitive fuels;
 
  •  the demand for electricity;
 
  •  the impact of energy conservation efforts; and
 
  •  the extent of governmental regulation and taxation.
 
The use of derivative financial instruments could result in material financial losses by ETP.
 
From time to time, ETP has sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms and by the activities ETP conducts in its trading operations. To the extent that ETP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change in ETP’s favor. In addition, even though monitored by management, ETP’s hedging and trading activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed.
 
Our success depends upon our 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


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time. Accordingly, ETP’s cash flows will also decline unless it is able to access new supplies of natural gas by connecting additional production to these systems.
 
ETP’s transportation pipelines are also dependent upon natural gas production in areas served by its pipelines or in areas served by other gathering systems or transportation pipelines that connect with its transportation pipelines. A material decrease in natural gas production in ETP’s areas of operation or in other areas that are connected to ETP’s areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP handles, which would reduce ETP’s revenues and operating income. In addition, ETP’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the natural decline rate in ETP’s currently connected supplies.
 
Transwestern derives a significant portion of its revenue from charges to its customers for reservation of capacity, which charges Transwestern receives regardless of whether these customers actually use the reserved capacity. Transwestern also generates revenue from transportation of natural gas for customers without reserved capacity. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in the demand for natural gas transportation on the Transwestern system in the long run. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.
 
The volumes of natural gas ETP transports on its 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 provide assurance 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.
 
ETP’s results of operations and its ability to grow and to increase distributions to unitholders will depend, in part, on its ability to make acquisitions that are accretive to ETP’s distributable cash flow per unit.


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ETP may be unable to make accretive acquisitions for any of the following reasons, among others:
 
  •  because ETP is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
 
  •  because ETP is unable to raise financing for such acquisitions on economically acceptable terms; or
 
  •  because ETP is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does.
 
Furthermore, even if ETP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP may:
 
  •  fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
 
  •  decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
 
  •  significantly increase its interest expense or financial leverage if ETP incurs additional debt to finance acquisitions;
 
  •  encounter difficulties operating in new geographic areas or new lines of business;
 
  •  incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which ETP is not indemnified or for which the indemnity is inadequate;
 
  •  be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
 
  •  less effectively manage its historical assets, due to the diversion of ETP management’s attention from other business concerns; or
 
  •  incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
 
If ETP consummates future acquisitions, its capitalization and results of operations may change significantly. As ETP determines the application of its funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that ETP will consider.
 
If ETP does not continue to construct new pipelines, its future growth could be limited.
 
During the past several years, ETP has constructed several new pipelines, and ETP is currently involved in constructing several new pipelines. ETP’s results of operations and its ability to grow and to increase distributable cash flow per unit will depend, in part, on its ability to construct pipelines that are accretive to ETP’s distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
 
  •  ETP is unable to identify pipeline construction opportunities with favorable projected financial returns;
 
  •  ETP is unable to raise financing for its identified pipeline construction opportunities; or
 
  •  ETP is unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
 
Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or results from those projected prior to commencement of construction and other factors.


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Expanding ETP’s business by constructing new pipelines and treating and processing facilities subjects it to risks.
 
One of the ways that ETP has grown its business is through the construction of additions to its existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and require the expenditure of significant amounts of capital that ETP will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, ETP’s revenues may not increase immediately following the completion of particular projects. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. Moreover, ETP may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.
 
ETP depends on certain key producers for its supply of natural gas on the Southeast Texas System and North Texas System, and the loss of any of these key producers could adversely affect its financial results.
 
For ETP’s nine months ended May 31, 2007, Anadarko E&P Company, LP, Southern Bay Operating, LLC and Chesapeake Energy Corp. supplied ETP with approximately 52% of the Southeast Texas System’s natural gas supply. For ETP’s nine months ended May 31, 2007, Encana Oil and Gas (USA), Inc., XTO Energy Inc., and Chesapeake Energy Marketing, Inc. supplied ETP with approximately 58% of the North Texas System’s natural gas supply. ETP is not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply ETP, ETP would be adversely affected unless it was able to acquire comparable supplies of natural gas from other producers.
 
ETP depends on key customers to transport natural gas on its ETC Katy Pipeline System, ET Fuel System and HPL System.
 
ETP has nine- and ten-year fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on ETP’s pipelines. ETP also has an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which is referred to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. ETP has also entered into two eight-year natural gas storage contracts with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on ETP’s cash flow and results of operations if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
 
ETP completed its 42” pipeline expansion to Carthage in April 2007. The major shippers through the 42” pipeline expansion to interstate and intrastate markets are XTO Energy, Inc., EOG Resources, Inc., Chesapeake Energy Marketing, Inc., Encana Marketing (USA), Inc. Quicksilver Resources, Inc. and Leor Energy, L.P. These shippers have long-term contracts ranging from five to 10 years. The failure of these shippers to fulfill their contractual obligations could have a material adverse effect on ETP’s cash flow and results of operations


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if ETP was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
 
Federal, state or local regulatory measures could adversely affect ETP’s business.
 
ETP’s natural gas gathering and intrastate transportation activities are 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. The rates, terms and conditions of some of the transportation and storage services ETP provides on the Houston Pipe Line, the ETC Katy Pipeline, 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, New Mexico, Arizona, Oklahoma, Louisiana, Utah and Colorado, the states in which ETP operates these types of pipelines. ETP’s intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s business may be adversely affected.
 
ETP’s midstream gathering, processing and intrastate transportation operations are also subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Oklahoma, Louisiana, Utah and Colorado, 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 Pipe Line 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 Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.
 
The states in which ETP conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s


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gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.
 
Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws could result in the imposition of administrative, civil and criminal remedies.
 
The FERC and CFTC are pursuing legal actions against ETP relating to certain natural gas trading and transportation activities, and related third party claims have been filed against us and ETP.
 
On July 26, 2007, the Federal Energy Regulatory Commission (the “FERC”) issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight dates from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the Natural Gas Act (“NGA”). ETP allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by the McGraw - Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha Hub in west Texas on certain dates in December 2005. The FERC’s action against ETP also includes allegations related to ETP’s Oasis Pipeline, an intrastate pipeline that transports natural gas between the Waha Hub and the Katy Hub near Houston, Texas. The Oasis Pipeline also transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority, and subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis Pipeline include claims that the Oasis Pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity is expected to account for approximately 1.0% of ETP’s EBITDA for its 2007 fiscal year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers, (such as utilities and other end-user) and sales from its own production, and any other sales of natural gas by ETP would be required to be made at prices that would be subject to FERC approval. Also on July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that ETP violated provisions of the Commodity Exchange Act by attempting to manipulate natural gas prices in the Houston Ship Channel. It is alleged that such manipulation was attempted during the period from late September through early December 2005 to allow ETP to benefit financially from ETP’s commodities derivatives positions.
 
In its Order and Notice, the FERC is seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC ordered ETP to show cause why the allegations against ETP made in the Order and Notice are not true. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. The FERC has taken the position that, once it receives ETP’s response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. In its lawsuit, the CFTC is seeking civil penalties of $130,000 per violation, or three times the profit gained from each violation, and other ancillary relief. The CFTC has not specified the number of alleged violations or the amount of alleged profit related to the matters specified in its complaint. On October 15, 2007, ETP filed a motion to dismiss in the


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United States District Court for the Northern District of Texas on the basis that the CFTC has not stated a valid cause of action under the Commodity Exchange Act.
 
It is ETP’s position that its trading and transportation activities during the periods at issue complied in all material respects with applicable laws and regulations, and ETP intends to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, neither we nor ETP is able to predict the final outcome of these matters.
 
In addition to the FERC and CFTC legal actions, it is also possible that third parties will assert claims against ETP and ETE for damages related to these matters, which parties could include natural gas producers, royalty owners, taxing authorities, and parties to physical natural gas contracts and financial derivatives based on the Platts Inside FERC Houston Ship Channel index during the periods in question. In this regard, two natural gas producers have initiated legal proceedings against ETP and ETE for claims related to the FERC and CFTC claims. One of the producers has brought suit in Texas state court against ETP and ETE based on contractual and tort claims relating to alleged manipulation of natural gas prices at the Waha Hub in West Texas and the Houston Ship Channel and is seeking unspecified direct, indirect, consequential and punitive damages. The second producer has brought suit in Texas state court against ETP and ETE based on contract and tort claims relating to a natural gas purchase contract to which ETP and this producer are parties. This producer seeks unspecified damages and requests pre-arbitration discovery of information related to ETP’s activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. The producer also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5.9 million, plus interest and costs. In addition, a plaintiff has filed a putative class action against ETP in the United States District Court for the Southern District of Texas. This suit alleges that ETP unlawfully manipulated the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act, that ETP has the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, Waha, and Permian hubs, in order to benefit ETP’s natural gas physical and financial trading positions. The suit alleges that this unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels between December 29, 2003 and December 31, 2005, causing unspecified damages to plaintiff and all others who purchased and/or sold natural gas futures and options contracts on NYMEX during that period.
 
We are expensing the legal fees, consultants’ and related expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obligated to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obligated to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.
 
Transwestern is subject to laws, regulations and policies governing the rates it is allowed to charge for its services.
 
Laws, regulations and policies governing interstate natural gas pipeline rates could affect Transwestern’s ability to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. Natural gas companies must charge rates that are deemed to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are


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required to be on file with FERC in FERC-approved tariffs. Pursuant to the Natural Gas Act, existing rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. Further, other than for rates set under market-based rate authority, rates must be cost-based and the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level. Transwestern filed a general rate case in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file new cost-based rates until October 2011. In addition, shippers (other than shippers who have agreed not to challenge our tariff rates through 2010 pursuant to our recent settlement agreement with these shippers) may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services on a prospective basis. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.
 
The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future refinement or change.
 
The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates of an interstate petroleum products pipeline, Santa Fe Pacific Pipeline, or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification to those rates. The Court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, the FERC issued its first case-specific oil pipeline review of the income tax allowance issues in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income allowance. Further, in the December 2005 order, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through entities pay the maximum marginal tax rate of 35% and that non-corporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the new income tax allowance policy were appealed to the D.C. Circuit. In May 2007, the D.C. Circuit affirmed FERC’s favorable income tax allowance policy. As a result, we remain eligible to include an allowance in the tariff rates we charge for natural gas transportation on our Transwestern interstate pipeline system, subject to our ability to demonstrate compliance with FERC’s policy. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. As FERC has recently approved our tariff rates specified in a settlement agreement with shippers, the allowance for income taxes as a cost-of-service element in our tariff rates is not subject to challenge prior to the expiration of this settlement agreement in 2011.


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Transwestern is subject to laws, regulations and policies governing terms and conditions of service, which control many aspects of its business.
 
In addition to rate oversight, FERC’s regulatory authority extends to many other aspects of Transwestern’s business and operations, including:
 
  •  operating terms and conditions of service;
 
  •  the types of services Transwestern may offer to its customers;
 
  •  construction of new facilities;
 
  •  acquisition, extension or abandonment of services or facilities;
 
  •  reporting and information posting requirements;
 
  •  accounts and records; and
 
  •  relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
 
Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair Transwestern’s ability to compete for business or increase the cost and burden of operation.
 
Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for violations after August 8, 2005 up to $1.0 million per day for each violation.
 
Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.
 
ETP’s business involves hazardous substances and may be adversely affected by environmental regulation.
 
ETP’s natural gas 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 or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.
 
ETP may incur substantial environmental costs and liabilities because the underlying risks are inherent to its operations. Joint and several, strict liability may be incurred under environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons or wastes on, under, or from its properties and facilities, many of which have been used for industrial activities for a number of years. Private parties, including the owners of properties through which ETP’s gathering systems pass or facilities where its petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern Pipeline operations is approximately $12.3 million, which activities are expected to continue for several years.


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Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For instance, the Texas Commission on Environmental Quality, or TCEQ, recently adopted a rule further restricting the level of nitrogen oxides, or NOx, that may be emitted from stationary gas-fired reciprocating internal combustion engines located in counties comprising the Dallas-Fort Worth eight hour ozone non-attainment area. As a result of the adoption of this rule, by March 1, 2009, ETP must either modify or replace seven owned and 21 leased compressor units currently located in the Dallas-Fort Worth non-attainment area that do not satisfy the TCEQ’s new, more stringent NOx emission limitations. ETP is evaluating its options to comply with this rule and thus the costs to comply currently are not reasonably estimable but such costs ultimately could be material to the operations of ETP. Also, the U.S. Congress is actively considering legislation and more than a dozen states have already taken legal measures to reduce emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere. Moreover, the U.S. Supreme Court recently decided, in Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.
 
Any reduction in the capacity of, or the allocations to, ETP’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s pipelines, which would adversely affect ETP’s revenues and cash flow.
 
Users of ETP’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s pipelines. Any reduction in volumes transported in ETP’s pipelines would adversely affect its revenues and cash flow.
 
ETP encounters competition from other midstream, transportation and storage companies and propane companies.
 
ETP experiences competition in all of its markets. ETP’s principal areas of competition include obtaining natural gas supplies for the Southeast Texas System, North Texas System and Houston Pipe Line System and natural gas transportation customers for its transportation pipeline systems. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems owned by DCP Midstream, LLC. The 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 and the Oasis Pipeline compete with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub. 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 acquisitions of the Houston Pipe Line System in 2005 and the Transwestern Pipeline System in 2006 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,


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store and market natural gas, that may have greater financial resources and access to larger natural gas supplies than ETP does.
 
The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by our pipelines.
 
ETP’s propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:
 
  •  price,
 
  •  reliability and quality of service,
 
  •  responsiveness to customer needs,
 
  •  safety concerns,
 
  •  long-standing customer relationships,
 
  •  the inconvenience of switching tanks and suppliers, and
 
  •  the lack of growth in the industry.
 
The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.
 
Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American Tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on Tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
 
ETP is exposed to the credit risk of its customers, and an increase in the nonpayment and nonperformance by its customers could reduce its ability to make distributions to its unitholders, including to us.
 
The risks of nonpayment and nonperformance by ETP’s customers are a major concern in its business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP is subject to risks of loss resulting from nonpayment or nonperformance by its customers. Any substantial increase in the nonpayment and nonperformance by ETP’s customers could reduce its ability to make distributions to its unitholders, including to us.


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ETP may be unable to bypass the La Grange and North Texas processing plants, which could expose it to the risk of unfavorable processing margins.
 
Because of ETP’s ownership of the Oasis and ET Fuel Pipelines, it can generally elect to bypass the La Grange or North Texas processing plants when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the Southeast Texas System and North Texas System with lean gas transported on the Oasis and ET Fuel Pipelines. In some circumstances, such as when ETP does not have a sufficient amount of lean gas on the Oasis and ET Fuel Pipelines to blend with the volume of rich gas that it receives at the La Grange and North Texas processing plants, 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 nine months ended May 31, 2007, approximately 36% 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 markets 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 it has access. Many of these pipelines are owned by parties not affiliated with ETP. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.
 
ETP’s pipeline integrity program may cause it to incur significant costs and liabilities.
 
ETP’s operations are subject to regulation by the U.S. Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act, or HLPSA, pursuant to which the DOT has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the DOT, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements for its existing transportation assets other than Transwestern Pipeline will result in capital costs of $15.7 million during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $17.9 million during that period. During this same time period, ETP estimates that it will incur pipeline integrity operating and maintenance costs of $8.5 million with respect to its Transwestern Pipeline. Through May 31, 2007, a total of $11.8 million of capital costs and $12.0 million of operating and maintenance costs have been incurred


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for pipeline integrity testing. 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 ETE and, accordingly, adversely affect the market price of ETP’s common units.
 
ETP believes that it maintains adequate insurance coverage, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
 
Terrorist attacks aimed at ETP’s facilities could adversely affect its business, results of operations, cash flows and financial condition.
 
Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any terrorist


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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 third party 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 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 Products Operating L.P. 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.


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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
 
In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us or ETP as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. The value of our investment in ETP depends largely on ETP being treated as a partnership for federal income tax purposes.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state income taxes as well. Distributions to unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
If ETP were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.


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Current law may change, causing us or ETP to be treated as a corporation for federal income tax purposes or otherwise subjecting us or ETP to entity-level taxation. For example, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or ETP as an entity, the cash available for distribution to our unitholders would be reduced.
 
The tax treatment of our structure is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The U.S. federal income tax treatment of common unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. You should be aware that the U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS, and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. The present U.S. federal income tax treatment of an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. federal tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, Vinson & Elkins L.L.P. is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”
 
If the IRS contests the federal income tax positions we or ETP takes, the market for our common units or ETP common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.
 
The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we or ETP take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we or ETP take. A court may not agree with some or all of our counsel’s conclusions or the positions we or ETP take. Any contest with the IRS may materially and adversely impact the market for our common units or ETP’s common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us or ETP, and therefore indirectly by us, as a unitholder and as the owner of the general partner of ETP, reducing the cash available for distribution to our unitholders.


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Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income. In such case, unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.
 
Tax gain or loss on disposition of our common units could be more or less than expected.
 
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.
 
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
 
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the common units.
 
To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain depreciation and amortization positions that are inconsistent with existing Treasury Regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not give any subsequent holder of a unit any such amortization deduction. This approach understates deductions available to those Unitholders who own those units and may result in those unitholders believing that they have a higher tax basis in their units than is actually the case. This, in turn, may result in those unitholders reporting less gain or more loss on a sale of their units than is actually the case.
 
The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a unitholder can identify the units to which this issue relates


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once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period under audit as if all unitholders owned such units.
 
Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders.
 
A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to you.
 
ETP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of ETP. The IRS may challenge this treatment, which could adversely affect the value of ETP’s common units and our common units.
 
When we or ETP issue additional units or engage in certain other transactions, ETP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s unitholders and us. Although ETP may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. ETP’s methodology may be viewed as understating the value of ETP’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP unitholders and us, which may be unfavorable to such ETP unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ETP’s intangible assets and a lesser portion allocated to ETP’s tangible assets. The IRS may challenge ETP’s valuation methods, or our or ETP’s allocation of Section 743(b) adjustment attributable to ETP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’s unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders or the ETP unitholders. It also could affect the amount of gain on the sale of common units by our unitholders or ETP’s unitholders and could have a negative impact on the value of our common units or those of ETP or result in audit adjustments to the tax returns of our or ETP’s unitholders without the benefit of additional deductions.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.
 
Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a twelve month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior twelve month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.
 
Based on the information currently available to us, we believe and intend to take the position that the sale of our common units by Ray C. Davis and Natural Gas Partners VI, L.P. to Enterprise GP Holdings, L.P. on May 7, 2007, together with all other common units sold within the prior twelve months, represented a sale or


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exchange of 50% or more of the total interest in our capital and profits interests and resulted in our termination and immediate reconstitution as a new partnership for federal income tax purposes. Moreover, our termination resulted in a deemed transfer of all of our interests in ETP, causing a termination of ETP’s partnership for federal income tax purposes. These terminations do not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. The closing of our taxable years will result in us and ETP both filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year. Moreover, these terminations will require both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP will be required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the unitholders of ETP (including Heritage Holdings as the holder of our Class E units) and, consequently, to our unitholders. However, elections ETP and ETE will make with respect to the amortization of certain intangible assets should have the effect of reducing the amount of taxable income that would otherwise be allocated to ETE unitholders.
 
We believe that the net effect of our tax termination and the tax termination of ETP will be an allocation for the 2007 calendar year of (i) an increased amount of taxable income as a percentage of the cash distributed to our unitholders who acquired their units prior to our initial public offering in February 2006 and (ii) a decrease in the amount of taxable income as a percentage of the cash distributed to our unitholders who purchased their units on or after the date of our initial public offering in February 2006. We estimate, based on our current distribution levels and various assumptions regarding the gross income and capital expenditures of ETP, that a unitholder who purchased our units on the date of our initial public offering or a new purchaser of our units would be allocated taxable income of less than 10% of the cash distributed to them for the 2008 calendar year. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our income or loss being includable in their taxable income for the year of termination.
 
You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
 
In addition to federal income taxes, the unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ETP do business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in us.


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USE OF PROCEEDS
 
The common units to be offered and sold using this prospectus will be offered and sold by the selling unitholders named in this prospectus or in any supplement to this prospectus. We will not receive any proceeds from the sale of such common units.


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DESCRIPTION OF OUR COMMON UNITS
 
Generally, our common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and our general partner in and to cash distributions, please read “Our Cash Distribution Policy.”
 
Our outstanding common units trade on the NYSE under the symbol “ETE.”
 
Transfer Agent and Registrar
 
American Stock Transfer & Trust Company serves as our registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of units, except the following that must be paid by unitholders:
 
  •  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
 
  •  special charges for services requested by a holder of a common unit; and
 
  •  other similar fees or charges.
 
There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
 
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
 
Transfer of Common Units
 
By transfer of our common units in accordance with our partnership agreement, each transferee of our common units will be admitted as a unitholder with respect to the common units transferred when such transfer and admission is reflected in our books and records except in the circumstances described below. Additionally, each transferee of our common units:
 
  •  represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
 
  •  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
 
  •  gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.
 
An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records except in the circumstances described below. The general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly. Although our general partner is not prevented from withholding its consent to an assignee requesting admission as a substituted limited partner, we do not anticipate that our general partner will exercise this right.
 
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.


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Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units except in the circumstances described below.
 
Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
 
We own an interstate pipeline that is subject to rate regulation of the Federal Energy Regulatory Commission, or FERC, and as a result our general partner has the right under our partnership agreement to institute procedures, by giving notice to each of our unitholders, that would require transferees of common units and, upon the request of our general partner, existing holders of our common units to certify that they are Eligible Holders. The purpose of these certification procedures would be to enable us to utilize a federal income tax expense as a component of the pipeline’s rate base upon which tariffs may be established under FERC rate making policies applicable to entities that pass-through their taxable income to their owners. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If these tax certification procedures are implemented, transferees of common units will be required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify;
 
  •  that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or
 
  •  that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.
 
In the event that this notice is given by our general partner, which we refer to as a “FERC Notice,” transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:
 
  •  becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;
 
  •  automatically requests admission as a substituted limited partner in our partnership;
 
  •  executes and agrees to be bound by the terms and conditions of our partnership agreement;
 
  •  represent that the transferee has the capacity, power and authority to enter into our partnership agreement;
 
  •  grants powers of attorney to the officers of our general partner and any liquidator of us as specified in our partnership agreement;
 
  •  gives the consents, covenants, representations and approvals contained in our partnership agreement; and
 
  •  certifies:
 
  •  that the transferee is an individual or is an entity subject to United States federal income taxation on the income generated by us; or
 
  •  that, if the transferee is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.


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Following a FERC Notice, an assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.
 
Following a FERC Notice, a transferee’s broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
 
Following a FERC Notice, in addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:
 
  •  the right to assign the common unit to a purchaser or other transferee; and
 
  •  the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.
 
As a result, following a FERC Notice, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:
 
  •  will not receive cash distributions;
 
  •  will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;
 
  •  may not receive some federal income tax information or reports furnished to record holders of common units; and
 
  •  will have no voting rights;
 
  •  unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.
 
The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure that the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent.
 
Class B Units
 
On March 27, 2007, all of the outstanding Class B units were converted into common units and, as a result, there are no longer any outstanding Class B units.


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Comparison of Rights of Holders of Our Common Units and ETP’s Common Units
 
The following table compares certain features of ETP’s common units and our common units.
 
         
   
ETP’s Common Units
 
Our Common Units
 
Taxation of Entity and Entity Owners
  ETP is a flow-through entity that is not subject to an entity-level federal income tax.   Similarly, we are a flow-through entity that is not subject to an entity-level federal income tax.
    ETP common unitholders generally will be allocated an amount of federal taxable income for the cumulative period ending December 31, 2008 related to ETP’s operations that is expected to be less than the cumulative amount of cash distributions that they receive with respect to that period.   Similarly, our common unitholders will be allocated an amount of federal taxable income for the cumulative period ending December 31, 2008 related to our operations that is expected to be less than the amount of cash distributions that they receive with respect to that period, although the ratio of taxable income allocated to our unitholders in relation to our cash distributions will be greater than the ratio of taxable income allocated to ETP’s unitholders in relation to its cash distributions.
    ETP common unitholders will receive Schedule K-1s from ETP reflecting the unitholders’ share of ETP’s items of income, gain, loss and deduction at the end of each calendar year.   Our common unitholders also will receive Schedule K-1s from us reflecting the unitholders’ share of our items of income, gain, loss and deduction at the end of each calendar year.
Sources of Cash Flow
  ETP is our subsidiary and may engage in acquisition and development activities that expand its business and operations.   Our cash-generating assets consist of our partnership interests in ETP, including incentive distribution rights, and we currently have no independent operations. Accordingly, our financial performance and our ability to pay cash distributions to our unitholders is currently directly dependent upon the performance of ETP. In the future, if we elect to develop independent operations, we may own assets or engage in businesses that compete directly or indirectly with ETP, except that ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States.
Limitation on Issuance of Additional Units
  ETP may issue an unlimited number of additional partnership interests and other equity securities without obtaining unitholder approval.   Similarly, we may issue an unlimited number of additional partnership interests and other equity securities without obtaining unitholder approval.
 
ETP also has outstanding class E units, none of which are publicly traded. Please read “Material Provisions of ETP’s Partnership Agreement — ETP Units” for a discussion of other classes of ETP units.


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OUR CASH DISTRIBUTION POLICY
 
Set forth below is a summary of our cash distribution, including a description of the significant provisions of our partnership agreement that relate to cash distributions as well as a description of restrictions on our ability to make cash distributions.
 
General
 
Our partnership agreement requires that, within 50 days after the end of each quarter, we distribute all of our available cash to the holders of record or our common units on the applicable record date.
 
Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:
 
  •  less the amount of cash reserves necessary or appropriate, as determined in good faith by our general partner, to:
 
  •  satisfy general, administrative and other expenses and debt service requirements;
 
  •  permit Energy Transfer Partners GP to make capital contributions to ETP in order to maintain its 2% general partner interest as required by ETP’s partnership agreement upon the issuance of additional partnership securities by ETP;
 
  •  comply with applicable law or any debt instrument or other agreement;
 
  •  provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters; and
 
  •  otherwise provide for the proper conduct of our business;
 
  •  plus all cash on hand immediately prior to the date of the distribution of available cash for the quarter.
 
Rationale for our Cash Distribution Policy.  Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than retaining it. It is important that you understand that our only cash-generating assets currently consist of partnership interests, including incentive distribution rights, in ETP from which we receive quarterly distributions. We currently have no independent operations outside of our interests in ETP. Because we believe we will have relatively low cash requirements for operating expenses and that we will finance any material capital investments from external financing sources, we believe that our investors are best served by distributing all of our available cash as described below. Because we are not subject to an entry-level federal income tax, we expect to have more cash to distribute to you than would be the case were we subject to tax. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.
 
Restrictions and Limitations on our Ability to Change our Cash Distribution Policy.  There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time. These restrictions include the following:
 
  •  Our distribution policy is subject to restrictions on distributions under our credit facilities. Specifically, our credit facilities contain material financial tests and covenants that we will be required to satisfy. Should we be unable to comply with the restrictions under our credit facilities, we would be prohibited from making cash distributions to you notwithstanding our stated distribution policy.
 
  •  ETP’s distribution policy is subject to restrictions on distributions under its credit agreements. Specifically, ETP’s credit agreements contain material financial tests and covenants that it must satisfy. Should ETP be unable to comply with the restrictions under its credit agreements, ETP would be prohibited from making cash distributions to us, which in turn would prevent us from making cash distributions to you notwithstanding our stated distribution policy. In addition, ETP would enter into new credit agreements containing financial tests and covenants that are more difficult to satisfy than those described in this prospectus.


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  •  The board of directors of our general partner has the authority under our partnership agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.
 
  •  The board of directors of ETP’ s general partner has the authority under ETP’ s partnership agreement to establish reserves for the prudent conduct of ETP’s business and for future cash distributions to ETP’s unitholders, and the establishment of those reserves could result in a reduction in cash distributions that we would otherwise anticipate receiving from ETP, which in turn could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.
 
  •  While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including our cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units. As of May 31, 2007, our affiliates, excluding Enterprise GP Holdings L.P., own approximately 37.4% of our outstanding common units.
 
  •  Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our cash distribution policy is subject to the determination of our general partner, taking into consideration the terms of our partnership agreement.
 
  •  The amount of distributions paid under ETP’s cash distribution policy is subject to the determination of ETP’s general partner, taking into consideration the terms of its partnership agreement.
 
  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
 
  •  We may lack sufficient cash to pay distributions to our unitholders due to increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs of us or ETP and its subsidiaries.
 
Our Cash Distribution Policy Limits Our Ability to Grow.  As with most other master limited partnerships, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. In fact, since our only cash-generating assets currently consist of our partnership interests in ETP, including incentive distribution rights, our growth initially will be dependent upon ETP’s ability to increase its quarterly distribution per unit. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.
 
ETP’s Ability to Grow is Dependent on its Ability to Access External Growth Capital.  Consistent with the terms of its partnership agreement, ETP has distributed to its partners most of the cash generated by its operations. As a result, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund its acquisition and growth capital expenditures. Accordingly, to the extent ETP is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent ETP issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that ETP will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or other debt to finance its growth strategy would result in increased interest expense to ETP, which in turn may impact the available cash that we have to distribute to our unitholders.
 
General Partner Interest
 
As of the date of this prospectus, our general partner is entitled to approximately 0.5% of all distributions that we make prior to our liquidation. This general partner interest is represented by 692,065 general partner units. The general partner’s initial 0.5% interest in these distributions will be proportionately reduced if we


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issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.5% general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.
 
Adjustments to Capital Accounts
 
We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.
 
Distributions of Cash upon Liquidation
 
If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in the partnership agreement and by law and, thereafter, we will distribute any remaining proceeds to the unitholders and our general partner in accordance with their respective capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.


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ETP’S CASH DISTRIBUTION POLICY
 
Following is a description of the relative rights and preferences of holders of ETP’s common units and ETP’s general partner in and to cash distributions.
 
Distributions of Available Cash
 
General.  ETP distributes all of its “available cash” to its unitholders and its general partner within 45 days following the end of each fiscal quarter.
 
Definition of Available Cash.  Available cash of ETP is defined in ETP’s partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:
 
  •  less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner of ETP to:
 
  •  provide for the proper conduct of its business;
 
  •  comply with applicable law or any debt instrument or other agreement (including reserves for future capital expenditures and for its future credit needs); or
 
  •  provide funds for distributions to ETP’s unitholders and its general partner in respect of any one or more of the next four quarters;
 
  •  plus all of ETP’s cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings of ETP made after the end of the quarter. Working capital borrowings are generally borrowings that are made under ETP’s credit facilities and in all cases are used solely for working capital purposes or to pay distributions to ETP’s partners.
 
Operating Surplus and Capital Surplus
 
General.  All cash distributed to ETP’s unitholders is characterized as either “operating surplus” or “capital surplus.” ETP distributes available cash from operating surplus differently than its available cash from capital surplus.
 
Definition of Operating Surplus.  ETP’s operating surplus for any period generally means:
 
  •  its cash balance on the closing date of its initial public offering in 1996; plus
 
  •  $10.0 million (as described below); plus
 
  •  all of ETP’s cash receipts since the closing of its initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
 
  •  ETP’s working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
 
  •  all of ETP’s operating expenditures after the closing of its initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
 
  •  the amount of ETP’s cash reserves that the general partner of ETP deems necessary or advisable to provide funds for future operating expenditures.
 
Definition of Capital Surplus.  Generally, ETP’s capital surplus will be generated only by:
 
  •  borrowings other than working capital borrowings;
 
  •  sales of ETP’s of debt and equity securities; and


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  •  ETP’s sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
 
Characterization of Cash Distributions.  ETP treats all of its available cash distributed as coming from its operating surplus until the sum of all available cash distributed since it began operations equals the operating surplus as of the most recent date of determination of available cash. ETP treats any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million in addition to its cash balance on the closing date of its initial public offering in 1996, cash receipts from its operations and cash from working capital borrowings. This amount does not reflect actual cash on hand that is available for distribution to its unitholders. Rather, it is a provision that enables ETP, if it chooses, to distribute as operating surplus up to $50.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We have not made, and we do not anticipate that we will make, any distributions from capital surplus.
 
Incentive Distribution Rights
 
ETP’s incentive distribution rights represent the contractual right of the general partner of ETP to receive a specified percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution has been paid by ETP. Please read “— Distributions of Available Cash from Operating Surplus” below. ETP’s general partner owns all of the incentive distribution rights, except that in conjunction with the August 2000 transaction with Energy Transfer Partners GP, L.P., ETP issued 1,000,000 class C units to Heritage Holdings, its general partner at that time, in conversion of that portion of Heritage Holdings’ incentive distribution rights that entitled it to receive any distribution made by ETP of funds attributable to the net amount received by ETP in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation. In January 2004, the class C units were distributed by Heritage Holdings to the owners of its equity interests. On July 14, 2006, all 1,000,000 outstanding class C units were retired and cancelled.
 
Distributions of Available Cash from Operating Surplus
 
ETP is required to make distributions of its available cash from operating surplus for any quarter in the following manner:
 
  •  First, 98% to all common, class E unitholders of ETP, in accordance with their percentage interests, and 2% to the general partner, until each common unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”);
 
  •  Second, 98% to all common, class E unitholders of ETP, in accordance with their percentage interests, and 2% to the general partner, until each common unit has received $0.275 per unit for such quarter (the “first target cash distribution”);
 
  •  Third, 85% to all common, class E unitholders of ETP, in accordance with their percentage interests, 13% to the holders of incentive distribution rights, pro rata, and 2% to the general partner, until each common unit has received $0.3175 per unit for such quarter (the “second target cash distribution”);
 
  •  Fourth, 75% to all common, class E unitholders of ETP, in accordance with their percentage interests, 23% to the holders of incentive distribution rights, pro rata, and 2% to the general partner, until each common unit has received $0.4125 per unit for such quarter (the “third target cash distribution”); and
 
  •  Fifth, thereafter, 50% to all common, class E unitholders of ETP, in accordance with their percentage interests, 48% to the holders of incentive distribution rights, pro rata, and 2% to the general partner.
 
Notwithstanding the foregoing, the distributions to the class E unitholders may not exceed $1.41 per unit per year.


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Distributions of Available Cash from Capital Surplus
 
ETP will make distributions of its available cash from capital surplus, if any, in the following manner:
 
  •  First, 98% to all of its unitholders, pro rata, and 2% to its general partner, until ETP distributes for each ETP common unit, an amount of available cash from capital surplus equal to its initial public offering price; and
 
  •  Thereafter, ETP will make all distributions of its available cash from capital surplus as if they were from operating surplus.
 
ETP’s partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price per ETP common unit less any distributions of capital surplus per unit is referred to as the “unrecovered capital” of ETP.
 
If ETP combines its units into fewer units or subdivide its units into a greater number of units, ETP will proportionately adjust its minimum quarterly distribution; its target cash distribution levels; and its unrecovered capital.
 
For example, if a two-for-one split of the common units of ETP should occur, the unrecovered capital of ETP would each be reduced to 50% of its initial level. ETP will not make any adjustment by reason of its issuance of additional units for cash or property.
 
On January 14, 2005, ETP’s general partner announced a two-for-one split of its common units that was effected on March 15, 2005. As a result, the minimum quarterly distribution and the target cash distribution levels of ETP were reduced to 50% of their initial levels. The adjusted minimum quarterly distribution and the adjusted target cash distribution levels of ETP are reflected in the discussion above under the caption “Distributions of Available Cash from Operating Surplus.”
 
In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes ETP to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, ETP will reduce its minimum quarterly distribution and the target cash distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates.
 
Distributions of Cash Upon Liquidation
 
General.  If ETP dissolves in accordance with its partnership agreement, it will sell or otherwise dispose of its assets in a process called liquidation. ETP will first apply the proceeds of its liquidation to the payment of its creditors. ETP will distribute any remaining proceeds to its unitholders and its general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of its assets in liquidation.
 
Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of ETP’s general partner.
 
Manner of Adjustments for Gain.  The manner of the adjustment for gain is set forth in ETP’s partnership agreement in the following manner:
 
  •  First, to the general partner and the holders of units of ETP who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
 
  •  Second, 98% to the common unitholders of ETP, pro rata, and 2% to the general partner of ETP, until the capital account for each common unit is equal to the sum of:
 
  •  its unrecovered capital; and
 
  •  the amount of the minimum quarterly distribution of ETP for the quarter during which our liquidation occurs;


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  •  Third, 98% to all unitholders of ETP, pro rata, and 2% to the general partner of ETP, until we allocate under this paragraph an amount per ETP unit equal to:
 
  •  the sum of the excess of the first target cash distribution per ETP unit over the minimum quarterly distribution per ETP unit for each quarter of our existence; less
 
  •  the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the minimum quarterly distribution per ETP unit that it distributed 98% to its unitholders, pro rata, and 2% to its general partner, for each quarter of its existence;
 
  •  Fourth, 85% to all unitholders of ETP, pro rata, 13% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP, until ETP allocates under this paragraph an amount per ETP unit equal to:
 
  •  the sum of the excess of the second target cash distribution per ETP unit over the first target cash distribution per ETP unit for each quarter of ETP’s existence; less
 
  •  the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the first target cash distribution per ETP unit that it distributed 85% to the unitholders of ETP, pro rata, 13% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP for each quarter of its existence;
 
  •  Fifth, 75% to all unitholders of ETP, pro rata, 23% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP, until ETP allocates under this paragraph an amount per ETP unit equal to:
 
  •  the sum of the excess of the third target cash distribution per ETP unit over the second target cash distribution per ETP unit for each quarter of its existence; less
 
  •  the cumulative amount per ETP unit of any distributions of ETP’s available cash from operating surplus in excess of the second target cash distribution per ETP unit that it distributed 75% to the unitholders of ETP, pro rata, 23% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP for each quarter of its existence; and
 
  •  Sixth, thereafter, 50% to all unitholders of ETP, pro rata, 48% to the holders of the incentive distribution rights of ETP, pro rata, and 2% to the general partner of ETP.
 
Manner of Adjustments for Losses.  Upon ETP’s liquidation, ETP will generally allocate any loss to its general partner and its unitholders in the following manner:
 
  •  First, 98% to the holders of common units of ETP in proportion to the positive balances in their capital accounts and 2% to the general partner of ETP, until the capital accounts of the common unitholders of ETP have been reduced to zero; and
 
  •  Second, thereafter, 100% to the general partner of ETP.
 
Adjustments to Capital Accounts upon the Issuance of Additional Units.  ETP will make adjustments to its capital accounts upon its issuance of additional units. In doing so, ETP will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to its unitholders and its general partner in the same manner as it allocates gain or loss upon liquidation. In the event that ETP makes positive adjustments to its capital accounts upon its issuance of additional units, ETP will allocate any later negative adjustments to its capital accounts resulting from its issuance of additional units or upon its liquidation in a manner which results, to the extent possible, in its general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to its capital accounts had been made.


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MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT
 
The following is a summary of the material provisions of our partnership agreement.
 
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
 
  •  with regard to rights of holders of units, please read “Description of Our Common Units;” and
 
  •  with regard to allocations of taxable income and other matters, please read “Material Tax Consequences.”
 
Organization and Duration
 
We were formed in September 2002 as La Grange Energy, L.P., a Texas limited partnership. In February 2004, we changed our name to Energy Transfer Company, L.P. In August 2005, we converted from a Texas limited partnership to a Delaware limited partnership and changed our name to Energy Transfer Equity, L.P. We have a perpetual existence.
 
Purpose
 
Under our partnership agreement, we are permitted to engage, directly or indirectly, in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law, provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Power of Attorney
 
Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “— Amendments to Our Partnership Agreement.”
 
Capital Contributions
 
Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”
 
Limited Liability
 
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
 
  •  to remove or replace the general partner;
 
  •  to approve some amendments to the partnership agreement; or
 
  •  to take other action under the partnership agreement;
 
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited


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liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
 
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
 
Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. While we currently have no operations distinct from ETP, if in the future, by our ownership in an operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
 
Voting Rights
 
The following is a summary of the unitholder vote required for the matters specified below. In voting their units, affiliates of our general partner will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
 
     
Issuance of additional units
  No approval right.
Amendment of our partnership agreement
  Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of a majority of our outstanding units. Please read “— Amendments to Our Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets
  A majority of our outstanding units in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”
Dissolution of our partnership
  A majority of our outstanding units. Please read “— Termination or Dissolution.”
Reconstitution of our partnership upon dissolution
  A majority of our outstanding units. Please read “— Termination or Dissolution.”
Withdrawal of our general partner
  Under most circumstances, the approval of a majority of the units, excluding units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to June 30, 2015 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our general partner.”


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Removal of our general partner
  Not less than 662/3 of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our general partner.”
Transfer of the general partner interest
  Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other than an individual) or (ii) another entity in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the units, excluding units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2015. Please read “— Transfer of General Partner Interest.”
Transfer of ownership interests in our general partner
  No approval required at any time. Please read “— Transfer of Ownership Interests in our general partner.”
 
Issuance of Additional Securities
 
Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that are senior to, equal in rank with or junior to our units on terms and conditions established by our general partner in its sole discretion without the approval of our unitholders.
 
It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of units in our net assets.
 
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which units are not entitled.
 
Upon issuance of additional units or other partnership securities, our general partner will have the option but not the obligation to make additional capital contributions to the extent it desires to maintain its general partner interest in us. Our general partner and its affiliates have the right, which they may from time to time assign in whole or in part to any of their affiliates, to purchase units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain their percentage interests in us that existed immediately prior to the issuance. As of May 31, 2007, affiliates of our general partner, excluding Enterprise GP Holdings L.P., hold approximately 37.4% of our outstanding common units. The holders of units do not have preemptive rights to acquire additional units or other partnership interests in us.
 
Amendments to Our Partnership Agreement
 
General
 
Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of our outstanding units.

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Prohibited Amendments
 
No amendment may be made that would:
 
(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
 
(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.
 
The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units.
 
No Unitholder Approval
 
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:
 
(1) a change in the name of the partnership, the location of the partnership’s principal place of business, the partnership’s registered agent or its registered office;
 
(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
 
(3) a change that, in the sole discretion of our general partner, is necessary or advisable for the partnership to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
(4) an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;
 
(5) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
 
(6) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
 
(7) any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by the partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
 
(8) a change in our fiscal year or taxable year and related changes;
 
(9) certain mergers or conveyances set forth in our partnership agreement; and
 
(10) any other amendments substantially similar to any of the matters described in (1) through (9) above.
 
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee if our general partner determines that those amendments:
 
(1) do not adversely affect our limited partners in any material respect;


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(2) are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
 
(3) are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the partnership’s best interest and the best interest of our limited partners;
 
(4) are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
 
(5) are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
 
Opinion of Counsel and Unitholder Approval
 
Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described under “— Amendments to Our Partnership Agreement — No Unitholder Approval.” No other amendments to our partnership agreement requiring the approval of holders of at least 90% of the outstanding units will become effective unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.
 
Merger, Sale or Other Disposition of Assets
 
Our partnership agreement generally prohibits our general partner, without the prior approval of a majority of our outstanding units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.
 
If conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.
 
Termination or Dissolution
 
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
 
(1) the election of our general partner to dissolve us, if approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates;
 
(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
 
(3) the entry of a decree of judicial dissolution of our partnership; or


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(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.
 
Upon a dissolution under clause (4) above, the holders of a majority of our outstanding units may also elect, excluding any units held by our general partner and its affiliates, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates, subject to receipt by us of an opinion of counsel to the effect that:
 
  •  the action would not result in the loss of limited liability of any limited partner; and
 
  •  neither our partnership nor Energy Transfer Partners would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
 
Liquidation and Distribution of Proceeds
 
Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:
 
  •  first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and
 
  •  then, to all partners in accordance with the positive balance in the respective capital accounts.
 
Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.
 
Withdrawal or Removal of Our General Partner
 
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2015 without obtaining the approval of a majority of our outstanding units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2015, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates.
 
Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.
 
Our general partner may not be removed unless that removal is approved by not less than 662/3% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates


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are not voted in favor of such removal, our general partner will have the right to convert its general partner interest into units or to receive cash in exchange for such interests. Any removal of this kind is also subject to the approval of a successor general partner by a majority of our outstanding units, including those held by our general partner and its affiliates. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. Affiliates of our general partner, excluding Enterprise GP Holdings L.P., own approximately 37.4% of the outstanding common units.
 
In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
 
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
 
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
 
Transfer of General Partner Interest
 
Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:
 
  •  an affiliate of the general partner (other than an individual); or
 
  •  another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all or substantially all of its assets to another entity,
 
our general partner may not transfer all or any part of its general partner interest in us to another entity prior to obtaining the approval of a majority of the units outstanding, excluding units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
 
Our general partner and it affiliates may at any time transfer units to one or more persons without unitholder approval.
 
Transfer of Ownership Interests in Our General Partner
 
At any time, Kelcy L. Warren, Enterprise GP Holdings L.P. and Natural Gas Partners VI, L.P., as the members of our general partner, may sell or transfer all or part of their ownership interest in the general partner without the approval of our unitholders.


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Change of Management Provisions
 
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner as general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.
 
Limited Call Right
 
If at any time our general partner and its affiliates hold more than 90% of the outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:
 
  •  the highest cash price paid by either our general partner or any of its affiliates for any limited partners interests of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase the limited partner interests; and
 
  •  the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed.
 
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences — Disposition of Units.”
 
Affiliates of our general partner, excluding Enterprise GP Holdings L.P., own approximately 83.6 million of our common units, representing approximately 37.4% of our outstanding common units. Enterprise GP Holdings L.P. owns approximately 39.0 million of our common units, representing approximately 17.4% of our outstanding common units.
 
Non-Taxpaying Assignees; Redemption
 
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, transferees of common units will be required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify;
 
  •  that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or
 
  •  that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.


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This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.
 
If, following institution of the certification procedures by our general partner, unitholders owning 10% or more of our outstanding common units, in the aggregate:
 
  •  fail to furnish a transfer application containing the required certification;
 
  •  fail to furnish a re-certification containing the required certification within 30 days after request; or
 
  •  is unable to provide a certification to the effect set forth in one of the two bullet points in the second preceding paragraph; then
 
we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by any such unitholder by giving written notice of redemption to such unitholder.
 
The purchase price in the event of such an acquisition for each unit held by such unitholder will be equal to the current market price as of the date of redemption.
 
The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.
 
Meetings; Voting
 
Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by non-citizen assignees will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.
 
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
 
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.
 
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.


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Status as Limited Partner
 
By transfer of units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the transferred units when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the units will be fully paid, and unitholders will not be required to make additional contributions.
 
Non-Citizen Assignees; Redemption
 
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.
 
Indemnification
 
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
 
(1) our general partner;
 
(2) any departing general partner;
 
(3) any person who is or was an affiliate of our general partner or any departing general partner;
 
(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;
 
(5) any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of the general partner or any departing general partner; and
 
(6) any person designated by our general partner.
 
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.
 
Reimbursement of Expenses and Administrative Fee
 
Our general partner receives a management fee of $500,000 for its management of us. Under the terms of the shared services agreement, we pay ETP an annual administrative fee of $500,000 and reimburse ETP at cost for all services to us for the provision of various general and administrative services for our benefit.
 
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.


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Books and Reports
 
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
 
We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
 
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
 
Right to Inspect Our Books and Records
 
A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, obtain:
 
  •  a current list of the name and last known address of each partner;
 
  •  a copy of our tax returns;
 
  •  information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
 
  •  copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement;
 
  •  information regarding the status of our business and financial condition; and
 
  •  any other information regarding our affairs as is just and reasonable.
 
Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.
 
Registration Rights
 
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.


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MATERIAL PROVISIONS OF
ETP’S PARTNERSHIP AGREEMENT
 
The following is a summary of material provisions of ETP’s partnership agreement. For more information on distributions of ETP’s available cash, please read “ETP’s Cash Distribution Policy.”
 
Voting Rights
 
ETP unitholders do not have voting rights except with respect to the following matters, for which ETP’s partnership agreement requires the approval of the holders of a majority of the units, unless otherwise indicated:
 
  •  a merger of ETP;
 
  •  a sale or exchange of all or substantially all of the assets of ETP;
 
  •  dissolution or reconstitution of ETP upon dissolution;
 
  •  certain amendments to ETP’s partnership agreement; and
 
  •  the transfer to another person of ETP’s incentive distribution rights at any time, except for transfers to affiliates of the general partner or transfers in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person.
 
The removal of ETP’s general partner requires the approval of not less than 662/3% of all outstanding units, including units held by its general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by ETP’s general partner and its affiliates.
 
Issuance of Additional Securities
 
ETP’s partnership agreement authorizes it to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by its general partner in its general partners’ sole discretion, without the approval of the unitholders. Any such additional partnership securities may be senior to the common units.
 
It is possible that ETP will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units ETP issues will be entitled to share equally with the then-existing holders of its common units in its distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in ETP’s net assets.
 
In accordance with Delaware law and the provisions of its partnership agreement, ETP may also issue additional partnership securities that, in the sole discretion of the general partner, may have special voting rights to which common units are not entitled.
 
Upon issuance of additional partnership securities, ETP’s general partner will be required to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in ETP. Moreover, ETP’s general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase ETP’s common units or other equity securities whenever, and on the same terms that, ETP issues those securities to persons other than its general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by ETP’s common units, that existed immediately prior to each issuance. The holders of ETP’s common units will not have preemptive rights to acquire additional common units or other partnership securities.
 
The following matters require the approval of the majority of the outstanding common units, including the common units owned by the general partner and its affiliates:
 
  •  a merger of our partnership;
 
  •  a sale or exchange of all or substantially all of our assets;


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  •  dissolution or reconstitution of our partnership upon dissolution;
 
  •  certain amendments to the partnership agreement; and
 
  •  the transfer to another person of our incentive distribution rights at any time, except for transfers to affiliates of the general partner or transfers in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person.
 
The removal of our general partner requires the approval of not less than 662/3% of all outstanding units, including units held by our general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by our general partner and its affiliates.
 
ETP Units
 
Common Units.  As of June 30, 2007, ETP had approximately 137.0 million common units outstanding, of which approximately 74.5 million were held by the public and approximately 62.5 million were held by ETE or its affiliates. As of such date, the common units represent an aggregate 98.0% limited partner interest in ETP. ETP’s general partner owns an aggregate 2.0% general partner interest in ETP. ETP’s common units are registered under the Securities Exchange Act of 1934, as amended and are listed for trading on the NYSE. The common units are entitled to distributions of Available Cash as described in “ETP’s Cash Distribution Policy.”
 
Class E Units.  8,853,832 class E units, all of which are held by our former general partner, Heritage Holdings. Heritage Holdings became our wholly-owned subsidiary in conjunction with the January 2004 Energy Transfer transactions. Class E units were converted from common units held by Heritage Holdings at that time. Class E units generally do not have voting rights; are entitled to aggregate distributions equal to a percentage of the total amount of cash distributed to all unitholders, up to a maximum of $1.41 per class E unit per year; and will be allocated 1% of any gain and an equivalent amount of any loss allocated to the common units in the event of a termination or liquidation of ETP. Because the owner of the class E units is our wholly-owned subsidiary, they are treated as treasury stock. Although distributions on the class E units will be available to us as the owner of Heritage Holdings, this amount will be reduced by the annual tax payments at corporate federal income tax rates that Heritage Holdings is required to pay with respect to distributions on the class E units.
 
Amendments to ETP’s Partnership Agreement
 
Amendments to ETP’s partnership agreement may be proposed only by ETP’s general partner. Certain amendments require the approval of a majority of the outstanding common units, including common units owned by the general partner and its affiliates. Any amendment that materially and adversely affects the rights or preferences of any class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the class of limited partnership interests so affected. However, in some circumstances, more particularly described in ETP’s partnership agreement, ETP’s general partner may make amendments to ETP’s partnership agreement without the approval of ETP’s unitholders to reflect:
 
  •  a change in ETP’s name, the location of its principal place of business, its registered agent or its registered office;
 
  •  the admission, substitution, withdrawal or removal of partners;
 
  •  a change to qualify or continue ETP’s qualification as a limited partnership or a partnership in which its limited partners have limited liability under the laws of any state or to ensure that neither ETP or HOLP will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
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  •  a change to (i) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, (ii) facilitate the trading of ETP’s common units or comply with any rule, regulation, guideline or requirement of any national securities exchange on which its common units are or will be listed for trading, (iii) that is necessary or advisable in connection with action taken by ETP’s general partner with respect to subdivision and combination of its securities or (iv) that is required to effect the intent expressed in ETP’s partnership agreement;
 
  •  a change in ETP’s fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in its fiscal year or taxable year;
 
  •  an amendment that is necessary to prevent ETP, or its general partner or its general partner’s directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended;
 
  •  an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of ETP’s securities;
 
  •  any amendment expressly permitted in ETP’s partnership agreement to be made by its general partner acting alone;
 
  •  an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with its partnership agreement;
 
  •  an amendment that is necessary or advisable to reflect, account for and deal with appropriately ETP’s formation of, or investment in, any corporation, partnership, joint venture, limited liability company or other entity other than its operating partnership, in connection with its conduct of activities permitted by its partnership agreement;
 
  •  a merger or conveyance to effect a change in ETP’s legal form; or
 
  •  any other amendments substantially similar to the foregoing.
 
Merger, Sale or Other Disposition of Assets
 
ETP’s general partner is generally prohibited, without the prior approval of the holders of at least a majority of the outstanding common units (excluding common units held by the general partner and its affiliates), from causing ETP to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions or approving on behalf of ETP the sale, exchange or other disposition of all or substantially all of the assets of its operating partnership; provided that its general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of ETP or its operating partnership without such approval. ETP’s general partner may also sell all or substantially all of ETP’s assets or its operating partnership’s assets pursuant to a foreclosure or other realization upon the foregoing encumbrances without such approval. Furthermore, provided that certain conditions are satisfied, the ETP’s general partner may merge ETP or any member of its partnership group into, or convey some or all of the partnership group’s assets to, a newly-formed entity if the sole purpose of such merger or conveyance is to effect a mere change in the legal form of ETP into another limited liability entity. ETP’s unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation of ETP, a sale of substantially all of ETP’s assets or any other transaction or event.


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Termination or Dissolution
 
ETP will continue as a limited partnership until terminated under its partnership agreement. ETP will dissolve upon:
 
(1) the expiration of ETP’s term under its partnership agreement;
 
(2) the election of ETP’s general partner to dissolve ETP, if approved by the holders of a majority of ETP’s outstanding common units, excluding those common units held by ETP’s general partner and its affiliates;
 
(3) the sale, exchange or other disposition of all or substantially all of ETP assets and properties and those of its subsidiaries;
 
(4) the entry of a decree of judicial dissolution of ETP; or
 
(5) the withdrawal or removal of ETP’s general partner or any other event that results in its ceasing to be ETP’s general partner other than by reason of a transfer of its general partner interest in accordance with ETP’s partnership agreement or withdrawal or removal following approval and admission of a successor.
 
Upon a dissolution under clause (5) above, the holders of a majority of ETP’s common outstanding units (excluding those common units held by ETP’s general partner and its affiliates) may also elect, within specific time limitations, to reconstitute ETP and continue its business on the same terms and conditions described in its partnership agreement by forming a new limited partnership on terms identical to those in ETP’s partnership agreement and having as general partner an entity approved by the holders of a majority of ETP’s outstanding common units, excluding those common units held by ETP’s general partner and its affiliates, subject to receipt by ETP of an opinion of counsel to the effect that:
 
  •  the action would not result in the loss of limited liability of any limited partner; and
 
  •  none of the partnership, the reconstituted limited partnership, ETP’s operating partnership nor any of its other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
 
Liquidation and Distribution of Proceeds
 
Upon ETP’s dissolution, unless it is reconstituted and continued as a new limited partnership, the person authorized to wind up ETP’s affairs (the liquidator) will, acting with all the powers of ETP’s general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate ETP’s assets. The proceeds of the liquidation will be applied as follows:
 
  •  first, towards the payment of all of ETP’s creditors and the creation of a reserve for contingent liabilities; and
 
  •  then, to all partners in accordance with the positive balance in the respective capital accounts.
 
Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of ETP’s assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to ETP’s partners, ETP’s general partner may distribute assets in kind to ETP’s partners.
 
Withdrawal or Removal of ETP’s General Partner
 
ETP’s general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of ETP’s partnership agreement. In addition, ETP’s general partner may withdraw without unitholder approval upon 90 days’ notice to ETP’s limited partners if at least 50% of ETP’s outstanding common units are held or controlled by one person and its affiliates other than its general partner and its affiliates.


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Upon the voluntary withdrawal of ETP’s general partner, the holders of a majority of ETP’s outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, ETP will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of its outstanding units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue ETP’s business and to appoint a successor general partner.
 
ETP’s general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of ETP’s outstanding units, including units held by its general partner and its affiliates, and ETP receives an opinion of counsel regarding limited liability and tax matters. In addition, if ETP’s general partner is removed as ETP’s general partner under circumstances where cause does not exist, ETP’s general partner will have the right to receive cash in exchange for its partnership interest as a general partner in ETP, its partnership interest as the general partner of any member of the Energy Transfer partnership group and its incentive distribution rights. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s general partner. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of ETP’s outstanding common units, including those held by its general partner and its affiliates.
 
While ETP’s partnership agreement limits the ability of ETP’s general partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of ETP’s general partner. In addition, ETP’s partnership agreement expressly permits the sale, in whole or in part, of the ownership of ETP’s general partner. ETP’s general partner may also transfer, in whole or in part, the common units it owns.
 
Transfer of General Partner Interests
 
ETP’s general partner may transfer all or any part of its general partner interest in ETP or its operating partnership to another person without the approval of the holders of outstanding common units; provided that, in each case, such transferee assumes the rights and duties of the general partner to whose interest such transferee has succeeded, agrees to be bound by the provisions of the partnership agreement, furnishes an opinion of counsel regarding limited liability and tax matters and agrees to acquire all (or the appropriate portion thereof, as applicable) of the general partner’s interest in each other member of ETP’s partnership group and agrees to be bound by the provisions of the operating partnership’s partnership agreement. The members of the general partner may also sell or transfer all or part of their interest in the general partner to an affiliate or a third party without the approval of the unitholders.
 
Change of Management Provisions
 
ETP’s partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove ETP’s general partner or otherwise change management:
 
  •  any units held by a person that owns 20% or more of any class of ETP’s units then outstanding, other than its general partner and its affiliates, cannot be voted on any matter; and
 
  •  the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about ETP’s operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Limited Call Right
 
If at any time less than 20% of the outstanding common units of any class are held by persons other than ETP’s general partner and its affiliates, its general partner will have the right to acquire all, but not less than all, of those common units at a price no less than their then-current market price. As a consequence, a


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unitholder may be required to sell his common units at an undesirable time or price. ETP’s general partner may assign this purchase right to any of its affiliates or ETP.
 
Reimbursement of Expenses
 
ETP’s partnership agreement requires it to reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on ETP’s behalf and all other expenses allocable to ETP or otherwise reasonably incurred by its general partner in connection with operating ETP’s business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for ETP or for its general partner in the discharge of its duties to ETP. ETP’s general partner is entitled to determine the expenses that are allocable to ETP in any reasonable manner in its sole discretion.
 
Indemnification
 
Under its partnership agreement, in most circumstances, ETP will indemnify ETP’s general partner, its general partner’s affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to ETP’s best interest. Any indemnification under these provisions will only be out of ETP’s assets. ETP’s general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to ETP to enable ETP to effectuate any indemnification. ETP is authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under its partnership agreement.
 
Registration Rights
 
Under its partnership agreement, ETP has agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by its general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. ETP is obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.


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MATERIAL TAX CONSEQUENCES
 
This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., tax counsel to the general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy Transfer Equity, L.P.
 
The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of units.
 
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.
 
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the units and the prices at which units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
 
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).
 
Partnership Status
 
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.
 
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids, certain related hedging activities, and our allocable share of income ETP’s income from these sources. Other types of qualifying income include interest


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(other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 6% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.
 
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Moreover, no ruling has been or will be sought from the IRS and the IRS has made no determination as to ETP’s status for federal income tax purposes or whether its operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership.
 
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:
 
  •  Neither we nor ETP has elected or will elect to be treated as a corporation; and
 
  •  For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.
 
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, in which case, the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
 
If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. Moreover, if ETP were taxable as a corporation in any taxable year, our share of ETP’s items of income, gain, loss and deduction would not be passed through to us and ETP would pay tax on its income at corporate rates. If we or ETP were taxable as corporations, losses recognized by ETP would not flow through to us or our losses would not flow through to our unitholders, as the case may be. In addition, any distribution made by us to a unitholder (or by ETP to us) would be treated as either taxable dividend income, to the extent of current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his units (or our tax basis in our interest in ETP), or taxable capital gain, after the unitholder’s tax basis in his units (or our tax basis in our interest in ETP) is reduced to zero. Accordingly, taxation of either us or ETP as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
 
The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we and ETP will be classified as partnerships for federal income tax purposes.


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Limited Partner Status
 
Unitholders who have become limited partners of us will be treated as partners in us for federal income tax purposes. Also:
 
  •  assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners; and
 
  •  unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units
 
will be treated as partners for federal income tax purposes. As there is no direct or indirect controlling authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.
 
A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”
 
Income, gains, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.
 
Tax Consequences of Unit Ownership
 
Flow-Through of Taxable Income.  We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
 
Treatment of Distributions.  Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the units, taxable in accordance with the rules described under “— Disposition of Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”
 
A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess


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of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.
 
Basis of Units.  A unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Units — Recognition of Gain or Loss.”
 
Limitations on Deductibility of Losses.  The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain would no longer be utilizable.
 
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
 
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. However, the application of the passive loss limitations to tiered publicly traded partnerships is uncertain. We will take the position that any passive losses we generate that are reasonably allocable to our investment in ETP will only be available to offset our passive income generated in the future that is reasonably allocable to our investment in ETP and will not be available to offset income from other passive activities or investments, including other investments in private businesses or investments we may make in other publicly traded partnerships. Moreover, because the passive loss limitations are applied separately with respect to each publicly traded partnership, any passive losses we generate will not be available to offset your income from other passive activities or investments, including your investments in other publicly traded partnerships, such as ETP, or salary or active business income. Further, your share of our net income may be offset by any suspended passive losses from your investment in us, but may not be offset by your current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party.


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The IRS could take the position that for purposes of applying the passive loss limitation rules to tiered publicly traded partnerships, such as ETP and us, the related entities are treated as one publicly traded partnership. In that case, any passive losses we generate would be available to offset income from your investments in ETP. However, passive losses that are not deductible because they exceed a unitholder’s share of income we generate would not be deductible in full until a unitholder disposes of his entire investment in both us and ETP in a fully taxable transaction with an unrelated party.
 
The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.
 
Limitations on Interest Deductions.  The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
 
  •  interest on indebtedness properly allocable to property held for investment;
 
  •  our interest expense attributed to portfolio income; and
 
  •  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
 
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
 
Entity-Level Collections.  If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.
 
Allocation of Income, Gain, Loss and Deduction.  In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders and our General Partner in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
 
Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as “Section 704(c) allocations,” to a unitholder purchasing units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future “reverse Section 704(c) allocations,” similar to the Section 704(c) allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of


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the future transaction. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although ETP does not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
 
An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
 
  •  his relative contributions to us;
 
  •  the interests of all the partners in profits and losses;
 
  •  the interest of all the partners in cash flow; and
 
  •  the rights of all the partners to distributions of capital upon liquidation.
 
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
 
Treatment of Short Sales.  A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
 
  •  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
 
  •  any cash distributions received by the unitholder as to those units would be fully taxable; and
 
  •  all of these distributions would appear to be ordinary income.
 
Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Units — Recognition of Gain or Loss.”
 
Alternative Minimum Tax.  Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
 
Tax Rates.  In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual where the asset disposed of was held for more than twelve months at the time of disposition is scheduled to remain at 15.0% for years 2008 through 2010 and then increase to 20% beginning January 1, 2011.


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Section 754 Election.  We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
 
Where the remedial allocation method is adopted (which we have historically adopted as to all property other than certain goodwill properties and which we will generally adopt as to all properties going forward), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. If we elect a method other than the remedial method with respect to a goodwill property, Treasury Regulation Section 1.197-2(g)(3) generally requires that the Section 743(b) adjustment attributable to an amortizable Section 197 intangible, which includes goodwill properties, should be treated as a newly-acquired asset placed in service in the month when the purchaser acquires the common unit. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. If we elect a method other than the remedial method with respect to a goodwill property, the common basis of such property is not amortizable. Please read “— Uniformity of Units.”
 
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of the property, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulation Section 1.197-2(g)(3). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
 
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the


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election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built–in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.
 
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets or the tangible assets owned by ETP to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.
 
Tax Treatment of Operations
 
Accounting Method and Taxable Year.  We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Units — Allocations Between Transferors and Transferees.”
 
Tax Basis, Depreciation and Amortization.  The tax basis of our assets and ETP’s assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by the unitholders immediately prior to this offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”
 
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Because our general partner may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill properties conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
 
If we or ETP dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own or ETP owns will likely be required to recapture some or all of those deductions as ordinary income upon a sale of


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his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Units — Recognition of Gain or Loss.”
 
The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.
 
Valuation and Tax Basis of Our Properties.  The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets and ETP’s assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
 
Disposition of Units
 
Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
 
Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.
 
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own or ETP owns. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
 
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or


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exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.
 
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
 
  •  a short sale;
 
  •  an offsetting notional principal contract; or
 
  •  a futures or forward contract with respect to the partnership interest or substantially identical property.
 
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
 
Allocations Between Transferors and Transferees.  In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
 
The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
 
A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
 
Notification Requirements.  A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder generally is also required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker, who will satisfy such requirements.
 
Constructive Termination.  We will be considered to have terminated our partnership 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. Likewise, ETP will be considered to have terminated its partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in ETP’s capital and profits within a twelve-month period. A termination would, among other things, result in the closing of our and/or ETP’s taxable years, as the case may be, for all unitholders, which would result in us and ETP both


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filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year, and could result in a deferral of certain deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs you may be allocated an increased amount of taxable income for the year in which we or ETP is considered to be terminated as a percentage of the cash distributed to you with respect to that period. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Moreover, in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.
 
Our termination, or the termination of ETP, currently would not affect our classification, or the classification of ETP, as a partnership for federal income tax purposes, but instead, we or ETP would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
 
Uniformity of Units
 
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”
 
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulation Section 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Units — Recognition of Gain or Loss.”
 
Tax-Exempt Organizations and Other Investors
 
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.


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Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
 
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
 
In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
 
Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
 
Administrative Matters
 
Information Returns and Audit Procedures.  We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
 
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
 
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names the general partner as our Tax Matters Partner.


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The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.
 
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
 
Nominee Reporting.  Persons who hold an interest in us as a nominee for another person are required to furnish to us:
 
  •  the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
  •  whether the beneficial owner is:
 
(1) a person that is not a United States person;
 
(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
 
(3) a tax-exempt entity;
 
  •  the amount and description of units held, acquired or transferred for the beneficial owner; and
 
  •  specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
 
Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.
 
Accuracy-Related Penalties.  An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
 
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
 
(1) for which there is, or was, “substantial authority”; or
 
(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.
 
If any item of income, gain, loss or deduction included in the distributive shares of unitholders for a given year might result in that kind of an “understatement” of income for which no “substantial authority” exists, we will disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for penalties. More stringent rules apply to “tax shelters,” which we do not believe includes us.


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A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.
 
Reportable Transactions.  If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”
 
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:
 
  •  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties,”
 
  •  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and
 
  •  in the case of a listed transaction, an extended statute of limitations.
 
We do not expect to engage in any “reportable transactions.”
 
State, Local, Foreign and Other Tax Considerations
 
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we or ETP do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We or ETP may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many other jurisdictions in which we may do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.
 
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.


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SELLING UNITHOLDERS
 
This prospectus covers the offering for resale of up to 66,625,100 common units by the selling unitholders identified below. No offer or sale may occur unless this prospectus has been declared effective by the SEC, and remains effective at the time such selling unitholder offers or sells such common units. We are required to update this prospectus to reflect material developments in our business, financial position and results of operations.
 
The following table sets forth certain information regarding the selling unitholders’ beneficial ownership of our common units as of September 25, 2007. The information presented below is based solely on our review of the Schedule 13D or 13G Statement of Beneficial Ownership filed by such person with the SEC or information otherwise provided by the selling unitholders.
 
                                 
                      Number of
 
          Percentage of
    Number of
    Common Units
 
    Number of
    Common Units
    Common Units
    Beneficially
 
    Common Units
    Beneficially
    That
    Owned
 
Name of Selling Unitholder
  Beneficially Owned     Owned     May be Sold(1)     After Offering  
 
Agile Performance Fund, LLC(2)
    37,547       *       37,547        
Anderson, Steven R
    186,404       *       186,404        
Ben Van de Bunt and Laura Fox Living Trust(2)
    36,484       *       36,484        
Brantley, Jr., David W
    235,736       *       102,646       133,090  
Burrow, Jeffrey Woodley
    401,471       *       205,293       196,178  
Continental Casualty Company(3)
    274,250       *       109,450       164,800  
The Cushing GP Strategies Fund, LP(3)
    367,729       *       200,657       167,072  
The Cushing MLP Opportunity Fund  I,LP(3)
    1,813,444       *       1,355,444       458,000  
DBB Energy Limited Partnership(4)
    783,218       *       341,037       442,181  
Denham Commodity Partners Fund LP(5)
    4,394,636       1.97 %     4,394,636        
ET Company Ltd.(6)
    49,126       *       49,126        
ET GP, LLC(6)
    6,796       *       6,796        
ETC Investors, Ltd.(6)
    1,454,140       *       1,454,140        
FHM Investments LLC(7)
    1,790,444       *       1,790,444        
GPS High Yield Equities Fund LP(2)
    180,181       *       180,181        
GPS Income Fund LP(2)
    735,491       *       735,491        
GPS New Equity Fund LP(2)
    230,036       *       230,036        
Greenhill Capital Partners, L.P.(8)
    2,092,079       *       2,092,079        
Greenhill Capital Partners (Cayman), L.P.(8)
    298,936       *       298,936        
Greenhill Capital Partners (Executives), L.P.(8)
    330,203       *       330,203        
Greenhill Capital, L.P.(8)
    659,271       *       659,271        
Hartz Capital MLP, LLC(9)
    912,076       *       912,076        
HFR RVA GPS Master Trust(2)
    131,338       *       131,338        
Kayne Anderson Capital Income Partners (QP), L.P.(10)
    78,223       *       78,223        
Kayne Anderson MLP Fund, L.P.(10)
    703,692       *       703,692        
Kayne Anderson MLP Investment Company(10)
    364,831       *       364,831        
Kellen Holdings, LLC(11)
    7,437,077       3.34 %     7,437,077        
Kile, Lon
    169,398       *       169,398        
Knee Family Trust(2)
    18,242       *       18,242        
Kutch, George Clayton
    471,472       *       205,293       266,179  
Kutch, Tracy
    205,293       *       205,293        
Lorenz, Renee Y
    410,586       *       410,586        


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                      Number of
 
          Percentage of
    Number of
    Common Units
 
    Number of
    Common Units
    Common Units
    Beneficially
 
    Common Units
    Beneficially
    That
    Owned
 
Name of Selling Unitholder
  Beneficially Owned     Owned     May be Sold(1)     After Offering  
 
L&E McMillian Family Partnership Ltd(12)
    205,293       *       205,293        
McCambro, Ltd.(13)
    136,586       *       136,586        
McReynolds Energy Partners, L.P.(14)
    4,359,553       1.96 %     4,359,553        
Nolan, John
    404,476       *       404,476        
Oasis Gas Partners LLC(15)
    6,084,881       2.73 %     6,084,881        
PH Investments, LLC(16)
    2,191,535       *       2,191,535        
Phillips Oil & Gas, Inc.(17)
    388,178       *       169,024       219,154  
Rainbow Investments Company(18)
    62,135       *       62,135        
The Renker Family Trust(2)
    36,484       *       36,484        
RMS-VMS, Ltd.(13)
    1,210,742       *       584,621       626,121  
Royal Bank of Canada(19)
    5,741,789       2.58 %     5,397,698       344,091  
Stallcup, John M
    15,534       *       15,534        
Swank MLP Convergence Fund, LP(3)
    364,831       *       364,831        
Tortoise Energy Capital Corporation(20)
    547,246       *       547,246        
Tortoise Energy Infrastructure Corporation(20)
    729,661       *       729,661        
UNC Investment Fund, LLC(21)
    605,658       *       405,658       200,000  
Kelcy Warren Partners, L.P.(22)
    17,264,898       7.75 %     17,136,398       128,500  
WH Energy Investors, L.L.C.(23)
    1,014,147       *       1,014,147        
The William P. and Jane C. Williams Family Partnership, Ltd.(24)
    721,207       *       721,207        
ZLP Fund, L.P.(25)
    625,782       *       625,782        
                                 
Totals
    69,970,466       31.40 %     66,625,100       3,345,366  
                                 
 
 
Less than 1%
 
(1) Because the selling unitholders may sell all or a portion of the common units registered hereby, we cannot estimate the number or percentage of common units that the selling unitholders will hold upon completion of the offering. Accordingly, the information presented in this table assumes that the selling unitholders will sell all of their common units registered pursuant hereto.
 
(2) This selling unitholder has advised that the natural person with voting and dispositive power over the common units beneficially owned by the selling unitholder is Steven Sugarman of GPS Partners LLC.
 
(3) This selling unitholder has advised that the natural person with voting and dispositive power over the common units beneficially owned by the selling unitholder is Jerry V. Swank as Managing Partner of Swank Energy Income Advisors, LP.
 
(4) DBB Energy Limited Partnership is a limited partnership owned by David W. Brantley, Jr. who may be deemed to beneficially own the limited partner interests held by DBB Energy Limited Partnership to the extent of his interest therein.
 
(5) Denham Commodity Partners Fund LP is an investment vehicle which is managed by Denham Commodity Partners GP LP as investment adviser. Denham GP LLC is the sole general partner of Denham Commodity Partners GP LP. Stuart Porter is the managing member of Denham GP LLC. Each of these persons may be deemed to have beneficial ownership of the securities.
 
(6) Ray C. Davis, Kelcy L. Warren and Natural Gas Partners VI, L.P. (“NGP”) are the sole members of ET GP, LLC. Therefore, each of Messrs. Davis and Warren and NGP may be deemed to have beneficial ownership of the common units owned by ETC GP, LLC to the extent of their ownership interests therein. 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 NGP, by virtue of GFW VI, L.L.C. being the sole general partner of G.F.W.

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Energy VI L.P. G.F.W. Energy VI, L.P., being the sole general partner of NGP. Messrs. Kenneth A. Hersh and David R. Albin, who constitute a majority of the members of such entity, 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. The general partner of ETC Investors, Ltd. is ET Company, Ltd., a limited partnership owned by Messrs. Davis and Warren.
 
(7) FHM Investments is owned by a group of former senior executive officers of ETP and one current senior executive officer of ETP.
 
(8) GCP Managing Partner, L.P., the managing general partners of the GCP Funds, as well as Greenhill Capital Partners, LLC, its general partner and Greenhill & Co., Inc., the sole member of Greenhill Capital Partners, LLC, may be deemed to beneficially own the units held by the Funds. Decisions regarding the investments by the Funds are made by an investment committee, the composition of which may change from time to time. The current members of the investment committee are Robert H. Niehaus, Scott L. Bok, Robert F. Greenhill, Simon A. Borrows, Kevin A. Bousquette and V. Frank Pottow, each of whom disclaims beneficial ownership of the units held by the Funds except to the extent of his pecuniary interest therein. In addition, with respect to decisions to dispose of the units held by the Funds, GCP Managing Partner, L.P. requires the consent of GCP, L.P., the general partner of which is GCP 2000, LLC, which in turn is controlled by its senior members, Messrs. Niehaus, Bok, Greenhill and Pottow. GCP, L.P. and GCP 2000, LLC may also be deemed to beneficially own the units held by the Funds. The address of the Funds is 300 Park Avenue, New York, New York 10022. Each of the Funds is an affiliate of a registered broker dealer and has informed us that it acquired the units in the ordinary course of its business and at the time the units were acquired, it had no agreements or understandings, directly or indirectly, with us or any of our affiliates or any person acting on our behalf or on behalf of our affiliates to distribute these shares.
 
(9) Edward J. Stern, Ronald J. Bangs and Jonathan B. Schindel, in their capacity as officers of Hartz Capital, Inc., which is the sole manager of Hartz Capital MLP, LLC, share voting and investment control over the shares held by Hartz Capital MLP, LLC. Each of Messers. Bangs and Schindel disclaims beneficial ownership of all of such shares.
 
(10) The number of common units is as of July 19, 2007 and does not include an aggregate of 1,304,223 common units owned by accounts managed by Kayne Anderson Capital Advisors, L.P. or KA Fund Advisors, L.P., each of which is an affiliate of the selling shareholder. Richard A. Kayne, in his capacity as the majority shareholder of Kayne Anderson Capital Advisors, L.P., holds voting and dispositive power with respect to the securities held by the selling unitholder. KA Associates, Inc., an affiliate of the selling unitholder, is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and is a member of the NASD. The selling unitholder (i) purchased the securities for the selling unitholder’s own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing securities in any transaction in violation of securities laws and (ii) at the time of purchase, the selling unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities.
 
(11) Kellen Holdings, LLC, a Delaware limited liability company, is a direct subsidiary of Liberty Energy Holdings, LLC, a Delaware LLC (“LEH”), and is an indirect subsidiary of Liberty Mutual Holding Company Inc., a Massachusetts mutual holding company. Liberty Mutual Holding Company Inc. is the ultimate controlling person of Kellen Holdings, LLC. Liberty Mutual Holding Company Inc. is a mutual holding company wherein its members are entitled to vote at meetings of the company. No such member is entitled to cast 10% or more of the votes. Liberty Mutual Holding Company Inc. has issued no voting securities.
 
(12) L&e McMillian Family Partnership Ltd is a limited partnership owned by Leonard McMillian, who may be deemed to beneficially own the limited partner interests held by the L&e McMillian Family Partnership Ltd to the extent of his interest therein.


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(13) McCambro, Ltd. and RMS-VMS, Ltd. are limited partnerships owned by Roger M. Smith who may be deemed to beneficially own the limited partner interests held by McCambro, Ltd. and RMS-VMS, Ltd., to the extent of his interest therein.
 
(14) McReynolds Energy Partners, L.P. is owned by Mr. McReynolds who may be deemed to beneficially own the limited partner interests held by McReynolds Energy Partners, L.P. to the extent of his respective interests therein.
 
(15) SF Holding Corp. may be deemed to beneficially own the common units owned of record by Oasis Gas Partners LLC, because SF Holding Corp. is the sole manager of Oasis Gas Partners LLC. The natural persons who hold voting and dispositive power over the units are the board of directors of SF Holdings Corp., Warren A. Stephens, W.R. Stephens Jr., Elizabeth Stephens Campbell, and Douglas H. Martin.
 
(16) PH Investments LLC is an investment vehicle which is managed by Amos B. Hostetter, Jr. Amos B. Hostetter, Jr. is the sole managing member of PH Investments, LLC. Amos B. Hostetter is the only person deemed to have beneficial ownership of the securities.
 
(17) This selling unitholder has advised that the natural person with voting and dispositive power over the common units beneficially owned by the selling unitholder is Fred L. Phillips, President of Phillips Oil & Gas, Inc.
 
(18) Rainbow Investments Company is an investment company controlled by Mr. Steven G. Herbst. Mr. Herbst may be deemed to have beneficial ownership of the securities.
 
(19) This unitholder has advised us that the unitholder is an affiliate of a U.S. registered broker-dealer; however, the unitholder acquired the common units in the ordinary course of business and, at the time of the acquisition, had no agreements or understandings, directly or indirectly, with any party to distribute the common units held by this unitholder.
 
(20) This unitholder has advised that Tortoise Capital Advisors, L.L.C. serves as the investment advisor to this unitholder and that, pursuant to an investment advisory agreement entered into with the unitholder, Tortoise Capital Advisors, L.L.C. holds voting and dispositive power with respect to the common units held by the unitholder. The unitholder has advised us that the investment committee of Tortoise Capital Advisors, L.L.C. is responsible for the investment management of the unitholder’s portfolio, such investment committee being comprised of H. Kevin Birzer, Zachary A. Hamel, Kenneth P. Malvey, Terry Matlack and David J. Schutle.
 
(21) This selling unitholder has advised that the natural person with voting and dispositive power over the common units beneficially owned by the selling unitholder is Jonathon C. King, President and Chief Executive Officer of UNC Management Company, Inc., the managing member of UNC Investment Fund, LLC.
 
(22) Kelcy Warren Partners, L.P., is a limited partnership owned by Mr. Warren. Mr. Warren disclaims beneficial ownership of the reported common units except to the extent of his pecuniary interest therein.
 
(23) WH Energy Investors, L.L.C. is an investment vehicle which is managed by its members consisting of A. Keith Weber, Ed Hawes and Sterling Holdings, LLC, a Kansas limited liability company. Leslie L. Webber and Patricia C. Webber are the sole owners of Sterling Holdings, LLC. Each of these persons may be deemed to have beneficial ownership of the securities.
 
(24) The William P. and Jane C. Williams Family Partnership, Ltd. is a limited partnership owned by William P. Williams who may be deemed to beneficially own the limited partner interests held by The William P. and Jane C. Williams Family Partnership, Ltd. to the extent of his interest therein.
 
(25) This selling unitholder has advised that the natural persons with voting and dispositive power over the common units beneficially owned by the selling unitholder are Stuart Zimmer and Greg Lucas of Zimmer Lucas Capital, LLC.


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Any prospectus supplement reflecting a sale of common units hereunder will set forth, with respect to the selling unitholders:
 
  •  the name of the selling unitholders;
 
  •  the nature of the position, office or other material relationship which the selling unitholders will have had within the prior three years with us or any of our affiliates;
 
  •  the number of common units owned by the selling unitholders prior to the offering;
 
  •  the amount or number of common units to be offered for the selling unitholders’ account; and
 
  •  the amount and (if one percent or more) the percentage of common units to be owned by the selling unitholders after the completion of the offering.
 
All expenses incurred with the registration of the common units owned by the selling unitholders will be borne by us.


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PLAN OF DISTRIBUTION
 
As of the date of this prospectus, we have not been advised by the selling unitholders as to any plan of distribution. Distributions of the common units by the selling unitholders, or by its partners, pledgees, donees (including charitable organizations), transferees or other successors in interest, may from time to time be offered for sale either directly by such individual, or through underwriters, dealers or agents or on any exchange on which the units may from time to time be traded, in the over-the-counter market, or in independently negotiated transactions or otherwise. The methods by which the common units may be sold include:
 
  •  a block trade (which may involve crosses) in which the broker or dealer so engaged will attempt to sell the securities as agent but may position and resell a portion of the block as principal to facilitate the transaction;
 
  •  purchases by a broker or dealer as principal and resale by such broker or dealer for its own account pursuant to this prospectus;
 
  •  exchange distributions and/or secondary distributions;
 
  •  sales in the over-the-counter market;
 
  •  underwritten transactions;
 
  •  short sales;
 
  •  broker-dealers may agree with the selling unitholders to sell a specified number of such common units at a stipulated price per unit;
 
  •  ordinary brokerage transactions and transactions in which the broker solicits purchasers;
 
  •  privately negotiated transactions;
 
  •  a combination of any such methods of sale; and
 
  •  any other method permitted pursuant to applicable law.
 
Such transactions may be effected by the selling unitholders at market prices prevailing at the time of sale or at negotiated prices. The selling unitholders may effect such transactions by selling the common units to underwriters or to or through broker-dealers, and such underwriters or broker-dealers may receive compensation in the form of discounts or commissions from the selling unitholders and may receive commissions from the purchasers of the common units for whom they may act as agent. The selling unitholders may agree to indemnify any underwriter, broker-dealer or agent that participates in transactions involving sales of the units against certain liabilities, including liabilities arising under the Securities Act. We have agreed to register the shares for sale under the Securities Act and to indemnify the selling unitholders and each person who participates as an underwriter in the offering of the units against certain civil liabilities, including certain liabilities under the Securities Act.
 
In connection with sales of the common units under this prospectus, the selling unitholders may enter into hedging transactions with broker-dealers, who may in turn engage in short sales of the common units in the course of hedging the positions they assume. The selling unitholders also may sell common units short and deliver them to close out the short positions, or loan or pledge the common units to broker-dealers that in turn may sell them.
 
The selling unitholders and any underwriters, broker-dealers or agents who participate in the distribution of the common units may be deemed to be “underwriters” within the meaning of the Securities Act. To the extent any of the selling unitholders are broker-dealers, they are, according to SEC interpretation, “underwriters” within the meaning of the Securities Act. Underwriters are subject to the prospectus delivery requirements under the Securities Act. If the selling unitholders is deemed to be an underwriter, the selling unitholders may be subject to certain statutory liabilities under the Securities Act and the Securities Exchange Act of 1934.
 
There can be no assurances that the selling unitholders will sell any or all of the common units offered under this prospectus.


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LEGAL MATTERS
 
Vinson & Elkins L.L.P., Houston, Texas, will pass upon the validity of the securities offered in this registration statement.
 
EXPERTS
 
The consolidated financial statements of Energy Transfer Equity, L.P. and LE GP, L.L.C., all incorporated in this prospectus by reference from our Annual Report on Form 10-K for the year ended August 31, 2006 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said reports.
 
The audited historical financial statements of Transwestern Pipeline Company, LLC as of December 31, 2005 and for the year then ended, included in Exhibit 99.2 of our Current Report on Form 8-K/A dated December 1, 2006 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.
 
The audited historical financial statements of Titan Energy Partners LP and Subsidiary (the “Partnership”) as of June 30, 2005 and for the periods from December 20, 2004 to June 30, 2005 and from July 1, 2004 to December 19, 2004 included in Exhibit 99.1 of our Current Report on From 8-K dated June 6, 2007 have been so incorporated in reliance on the reports (which contain an explanatory paragraph relating to the Partnership’s emergence from bankruptcy as described in Note 1 to the financial statements) of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.
 
WHERE YOU CAN FIND MORE INFORMATION
 
This prospectus, including any documents incorporated herein by reference, constitutes a part of a registration statement on Form S-3 that we filed with the SEC under the Securities Act. This prospectus does not contain all the information set forth in the registration statement. You should refer to the registration statement and its related exhibits and schedules, and the documents incorporated herein by reference, for further information about our company and the securities offered in this prospectus. Statements contained in this prospectus concerning the provisions of any document are not necessarily complete and, in each instance, reference is made to the copy of that document filed as an exhibit to the registration statement or otherwise filed with the SEC, and each such statement is qualified by this reference. The registration statement and its exhibits and schedules, and the documents incorporated herein by reference, are on file at the offices of the SEC and may be inspected without charge.
 
We file annual, quarterly, and current reports, proxy statements and other information with the SEC. You can read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You can obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains information we file electronically with the SEC, which you can access over the Internet at http://www.sec.gov.
 
Our home page is located at http://www.energytransfer.com. Our annual reports on Form 10-K, our quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC are available free of charge through our web site as soon as reasonably practicable after those reports or filings are electronically filed or furnished to the SEC. Information on our web site or any other web site is not incorporated by reference in this prospectus and does not constitute a part of this prospectus.


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INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
 
We are incorporating by reference in this prospectus information we file with the SEC, which means that we are disclosing important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus, and later information that we file with the SEC automatically will update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the SEC, including all such documents we may file after the date of the initial registration statement and prior to the effectiveness of the registration statement, under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act, excluding any information in those documents that is deemed by the rules of the SEC to be furnished not filed, until we close this offering:
 
  •  our annual report on Form 10-K for the year ended August 31, 2006;
 
  •  our quarterly reports on Form 10-Q for the periods ended November 30, 2006, February 28, 2007 and May 31, 2007; and
 
  •  our current reports on Form 8-K filed September 19, 2006, September 25, 2006, October 2, 2006, November 2, 2006, November 30, 2006, as amended, December 5, 2006, December 21, 2006, December 26, 2006, January 8, 2007, January 17, 2007, February 23, 2007, March 5, 2007, March 29, 2007, May 8, 2007, June 6, 2007, June 11, 2007, June 21, 2007, July 26, 2007, August 17, 2007, both on September 26, 2007, both on October 9, 2007 and October 15, 2007.
 
You may request a copy of these filings, which we will provide to you at no cost, by writing or telephoning us at the following address and telephone number:
 
Energy Transfer Equity, L.P.
3738 Oak Lawn Avenue
Dallas, Texas 75219
Attention: Sonia Aube
Telephone: (214) 981-0700


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Energy Transfer Equity, L.P.