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

 

 

 

 

 

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

 

November 7, 2007

 

TABLES OF CONTENTS

 

 

 

 

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.

	•	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.

	•	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.

	•	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 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 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.

	•	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 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.

	•	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

	•	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.

	•	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).

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

	•	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.

Public Common Units			44.6	%
General Partner Units			0.3	%
Management & Other Affiliates of Energy Transfer Equity			55.1	%
			100.0	%

(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.

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.”

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.”

		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.

 

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:

 

 

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

 

 

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:

 

 

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.

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:

 

 

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:

 

 

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

 

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

 

Sales by any of our existing unitholders of a substantial number of our units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

Control of our general partner may be transferred to a third party without Unitholder consent.

 

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner to sell or transfer all or part of their ownership interest in our general partner to a third party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by the Board of Directors and officers.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions in which we do business. In some of the jurisdictions in which we do business, the applicable statutes do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking

any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner if:

 

 

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:

 

 

 

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

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 fiduciary duties of our general partner’s officers and directors may conflict with those of ETP’s general partner.

 

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

 

The risk of competition with affiliates of our general partner has increased.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us.

Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. On May 7, 2007, Enterprise GP Holdings L.P. acquired a 34.9% non-controlling equity interest in our general partner. Enterprise GP Holdings L.P. and its subsidiaries are a North American midstream energy business. As a result, there is greater risk that competition with affiliates of our general partner could occur, which could adversely impact our results of operations and cash available for distribution.

 

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

 

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

 

 

Our 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:

 

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

 

 

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:

 

 

 

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

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 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

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.

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:

 

 

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:

 

 

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:

 

 

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,

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.

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

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.

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.

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:

 

 

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.

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

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:

 

 

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.

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

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

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

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

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

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,

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

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.

 

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.

 

 

 

 

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.

 

 

 

 

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:

 

 

 

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:

 

 

Summary of Operating Financial Performance in fiscal 2007

 

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

 

ETP’s Operations

 

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

 

Despite the warmer than normal winter, our propane operations were able to deliver higher than expected results. Our retail volumes increased as a result of acquisitions during fiscal year 2007 and the Titan and other acquisitions during fiscal year 2006 which offset the decrease in volumes we experienced due to the warmer weather. We also were able to increase our sales prices which improved our gross margins. Additionally, due to the acquisitions we made during fiscal years 2007 and 2006, our other propane segment revenues, such as appliance sales, labor and tank rentals, also improved over prior years.

 

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

 

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

Trends and Outlook

 

Looking to fiscal 2008, we believe our operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion activity completed during fiscal year 2007, additional capacity resulting from pipeline projects expected to be completed within the next twelve to eighteen months, 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

 

 

 

 

Intrastate Transportation and Storage

 

 

 

Interstate Transportation

 

 

 

Retail Propane

 

 

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:

 

 

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

 

Equity in Earnings of Affiliates.  Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its Class A and Class B limited partner interests of ETP GP and its investment in ETP LLC. The increase in equity in earnings of affiliates for the year ended August 31, 2007 compared to the year ended August 31, 2006 is directly related to the increased ownership in ETP as a result of the common, Class F and Class G unit acquisitions in February 2006 and November 2006 and the increased ownership of ETP IDRs, as discussed above, and the changes in the ETP segment income described below.

 

The change in equity in earnings of affiliates for the year ended August 31, 2006 compared to the year ended August 31, 2005 is directly related to the increased ownership of ETP as a result of the common and Class F unit acquisitions in February 2006 and the changes in the ETP segment income described below.

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

 

 

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.

Consolidated Results

 

 

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.

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

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:

 

 

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.

Midstream

 

 

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:

 

 

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

 

 

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

 

Midstream operating expenses increased $9.1 million between the years ended August 31, 2006 and 2005 and was primarily driven by $3.2 million in increased measurement expenses, $1.1 million in increased chemical costs,

$0.7 million in scheduled compressor and pipeline maintenance expense and pipeline integrity costs, $0.9 million in employee costs, and increases of $3.2 million in other operating expenses.

 

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

 

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

 

 

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:

 

 

 

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:

 

 

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

 

 

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

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

 

Retail Propane