Filed pursuant to Rule 424(b)(2)

Registration No. 333-164414

SUBJECT TO COMPLETION, DATED JANUARY 20, 2010

 

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus dated January 20, 2010)

 

$1,750,000,000

 

Energy Transfer Equity, L.P.

     % Senior Notes due 2017

     % Senior Notes due 2020

 

 

 

 

We are offering $     aggregate principal amount of our     % Senior Notes due 2017, or 2017 notes, and $      aggregate principal amount of our     % Senior Notes due 2020, or 2020 notes. We refer to the 2017 notes and 2020 notes, collectively, as the notes.

 

Interest on the notes will accrue from          , 2010 and will be payable semi-annually on February 28 and August 31 of each year, beginning on August 31, 2010. The 20   notes will mature on February 28, 2017 and the 2020 notes will mature on February 28, 2020.

 

We may redeem some or all of the notes at any time at a price equal to 100% of the principal amount of the notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date.

 

The notes are our unsecured senior obligations. If we default, your right to payment under the notes will rank equally with the right to payment of the holders of our other current and future unsecured senior debt.

 

If we experience a Change of Control together with a Rating Decline, each as defined herein, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase. See “Description of Notes — Covenants.”

 

The obligations to make payments of principal, premium, if any, and interest on the notes are solely our obligations. The notes will initially not be guaranteed by any of our subsidiaries, including Energy Transfer Partners, L.P.

 

None of the Securities and Exchange Commission, any state securities commission or any other U.S. regulatory authority has approved or disapproved of the securities nor have any of the foregoing authorities passed upon or endorsed the merits of this offering or the accuracy or adequacy of this prospectus supplement or the accompanying prospectus. Any representation to the contrary is a criminal offense.

 

Investing in the notes involves risks. See “Risk Factors” beginning on page S-15 of this prospectus supplement and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the notes.

 

 

 

The underwriters expect to deliver the notes to purchasers in book-entry form only through The Depository Trust Company on or about          , 2010.

 

Joint Book-Running Managers

 

Co-Managers

 

The date of this prospectus supplement is          , 2010.

 

TABLE OF CONTENTS

 

Prospectus Supplement

 

 

ABOUT THIS PROSPECTUS SUPPLEMENT

 

We provide information to you about the notes in two separate documents that offer varying levels of detail:

 

 

Generally, when we refer to this “prospectus,” we are referring to both documents combined.

 

You should rely only on the information contained in this prospectus supplement, the accompanying prospectus, any free writing prospectus prepared by us or on our behalf and the documents we have incorporated by reference. We have not authorized anyone else to give you different information. We are not offering the notes in any state where the offer is not permitted. You should not assume that the information in this prospectus supplement or in the accompanying prospectus is accurate as of any date other than the date on the front of those documents. If the description of this offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement. You should not assume that any information contained in the documents incorporated by reference in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

 

None of Energy Transfer Equity, L.P., the underwriters or any of their respective representatives is making any representation to you regarding the legality of an investment in the notes by you under applicable laws. You should consult with your own advisors as to the legal, tax, business, financial and related aspects of an investment in the notes.

 

WHERE YOU CAN FIND MORE INFORMATION

 

We file annual, quarterly, and current reports, proxy statements and other information with the SEC. You can read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You can obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains information we file electronically with the SEC, which you can access over the Internet at http://www.sec.gov.

 

Our home page is located at http://www.energytransfer.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings with the SEC are available free of charge through our web site as soon as reasonably practicable after those reports or filings are electronically filed or furnished to the SEC. Information on our web site or any other web site is not incorporated by reference in this prospectus supplement and does not constitute a part of this prospectus supplement.

 

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

 

We are incorporating by reference in this prospectus supplement and the accompanying prospectus information we file with the SEC, which means that we are disclosing important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus supplement and the accompanying prospectus, and later information that we file with the SEC automatically will update and supersede this information. We incorporate by reference in this prospectus supplement and the accompanying prospectus the documents listed below excluding any information in those documents that is deemed by the rules of the SEC to be furnished and not filed, until we close this offering:

 

 

 

You may obtain any of the documents incorporated by reference in this prospectus supplement or the accompanying prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus supplement and the accompanying prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at the address provided above or by writing or calling us at the address set forth below.

 

Energy Transfer Equity, L.P.

3738 Oak Lawn Avenue

Dallas, Texas 75219

Attention: Sonia Aubé

Telephone: (214) 981-0700

 

FORWARD-LOOKING STATEMENTS

 

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

 

 

 

 

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Risk Factors” in this prospectus supplement.

 

PROSPECTUS SUPPLEMENT SUMMARY

	•	an approximate 1.8% general partner interest, which ETE holds through its ownership interests in ETP GP;
	•	100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP; and
	•	approximately 62.5 million ETP common units, all of which are held directly by ETE.

	•	13.0% of all incremental cash distributed in a fiscal 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 fiscal 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 fiscal quarter after $0.4125 has been distributed in respect of each common unit of ETP for that quarter.

		Nine Months												Four Months
		Ended								Year Ended				Ended				Year Ended
		September 30,								December 31,				December 31,				August 31,
		2009				2008				2008				2007				2007
Limited Partner Interests		$	167,580			$	166,018			$	221,878			$	70,313			$	199,221
General Partner Interest			14,588				12,740				17,322				5,110				13,676
Incentive Distribution Rights			255,808				219,298				298,575				85,775				222,353
Total distributions received from ETP(1)		$	437,976			$	398,056			$	537,775			$	161,198			$	435,250

(1)		Represents cash distributions received in respect of each of the quarters included within the period, including distributions paid in respect of the last quarter of such period after the end of such quarter and excluding distributions paid during the first quarter of such period in respect of the prior quarter.

	•	In April 2007, ETP completed its 243-mile pipeline from Cleburne in north Texas to Carthage in east Texas, which we refer to as the Cleburne to Carthage pipeline, to expand its capacity to transport natural gas produced from the Barnett Shale and the Bossier Sands to its Texoma pipeline and other pipeline interconnections. The Cleburne to Carthage pipeline is primarily a 42-inch diameter natural gas pipeline. In December 2007, ETP completed two natural gas compression projects that added approximately 90,000 horsepower on the Cleburne to Carthage pipeline, increasing natural gas deliverability at the Carthage Hub to more than 2.0 Bcf/d.
	•	In April 2008, ETP completed its 150-mile Southeast Bossier 42-inch diameter natural gas pipeline, which we refer to as the Southeast Bossier pipeline. This pipeline connects ETP’s 42-inch diameter Cleburne to Carthage pipeline and its 30-inch diameter East Texas pipeline to its 30-inch diameter Texoma pipeline. The Southeast Bossier pipeline has an initial throughput capacity of 900 million cubic feet per day, or MMcf/d, which can be increased to 1.3 Bcf/d with the addition of compression. The Southeast Bossier pipeline increases ETP’s takeaway capacity from the Barnett Shale and Bossier Sands and provides increased market access for natural gas produced in these areas.
	•	In July 2008, ETP completed its 36-inch diameter Paris Loop natural gas pipeline expansion project in north Texas. This 135-mile pipeline initially provided ETP with an additional 400 MMcf/d of capacity out of the Barnett Shale, which increased to 900 MMcf/d in May 2009. The Paris Loop originates near Eagle Mountain Lake in northwest Tarrant County, Texas and connects to ETP’s Houston Pipe Line system near Paris, Texas.
	•	In August 2008, ETP completed an expansion of its Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub through the installation of 32 miles of 42-inch diameter pipeline. This expansion, which we refer to as the Carthage Loop, added 500 MMcf/d of pipeline capacity from Cleburne to the Carthage Hub. In September 2009, ETP increased the capacity of the Carthage Loop to 1.1 Bcf/d by adding compression to this pipeline.

	•	In August 2008, ETP completed the first segment of its 36-inch diameter Maypearl to Malone natural gas pipeline expansion project. This 25-mile pipeline extends from Maypearl, Texas to Malone, Texas, and provides an additional 600 MMcf/d of capacity out of the Fort Worth Basin.
	•	In January 2009, ETP completed its Southern Shale natural gas pipeline project, which consists of 31 miles of 36-inch diameter pipeline that originates in southern Tarrant County, Texas and delivers natural gas to its Maypearl to Malone pipeline expansion project. The Southern Shale pipeline provides an additional 700 MMcf/d of takeaway capacity from the Barnett Shale.
	•	In January 2009, ETP completed its 36-inch diameter Cleburne to Tolar natural gas pipeline expansion project. This 20-mile pipeline extends from Cleburne, Texas to Tolar, Texas and provides an additional 400 MMcf/d of takeaway capacity from the Barnett Shale.
	•	In February 2009, ETP completed its 56-mile Katy Expansion pipeline project. This 36-inch diameter expansion project increases the capacity of its existing ETC Katy natural gas pipeline in southeast Texas by more than 400 MMcf/d.
	•	In August 2009, ETP completed its Texas Independence Pipeline, which consists of approximately 150 miles of 42-inch diameter pipeline originating near Maypearl, Texas and ending near Henderson, Texas. This pipeline connects ETP’s ET Fuel System and North Texas System with its East Texas pipeline. The Texas Independence Pipeline expands ETP’s ET Fuel System’s throughput capacity by an incremental 1.1 Bcf/d and, with the addition of compression, the capacity may be expanded to 1.75 Bcf/d.

	•	ETP believes that the size and scope of its operations, its stable asset base and cash flow profile, and its investment grade status will be significant positive factors in its efforts to obtain new debt or equity financing in light of current market conditions.

	•	ETP’s experienced management team has an established reputation as highly-effective, strategic operators within its operating segments. In addition, ETP’s management team is motivated to effectively and efficiently manage its business operations through performance-based incentive compensation programs and through ownership of a substantial equity position in us and therefore benefits from incentive distribution payments ETP makes to ETP GP.

(1)		Includes approximately 540,000 common units owned by management of Energy Transfer Partners, L.P.
(2)		Includes unamortized discounts of ETP senior notes.
(3)		Does not include the outstanding debt of joint ventures MEP and FEP. See “Capitalization” and “Description of Other Indebtedness.”

Issuer		Energy Transfer Equity, L.P.
Notes Offered		We are offering $1,750,000,000 aggregate principal amount of notes of the following series:
		• $          % Senior Notes due 2017, and
		• $          % Senior Notes due 2020.
Maturity		The 2017 notes will mature on February 28, 2017 and the 2020 notes will mature on February 28, 2020.
Interest Rate		Interest on the 2017 notes will accrue at the per annum rate of     % and interest on the 2020 notes will accrue at the per annum rate of     %.
Interest Payment Dates		Interest on the notes will accrue from the issue date of the notes and be payable semi-annually on February 28 and August 31 of each year, beginning on August 31, 2010.
Ranking		The notes will be our senior obligations. The notes will rank equally in right of payment with all of our other existing and future senior unsubordinated indebtedness and senior to any of our subordinated indebtedness.
		The notes initially will not be guaranteed by any of our subsidiaries. However, if in the future any of our subsidiaries guarantees or becomes a co-obligor with respect to any indebtedness under our revolving credit facility, then such subsidiary will also guarantee the notes on terms provided for in the indenture. With respect to the assets of our subsidiaries that do not guarantee the notes, including ETP, the notes will effectively rank junior to all existing and future obligations of those subsidiaries. As of September 30, 2009, our subsidiaries, including ETP and its subsidiaries, had outstanding approximately $6.2 billion of indebtedness that would effectively rank senior to the notes with respect to the assets of those subsidiaries.
		The notes will be unsecured, and will effectively rank junior to our secured indebtedness to the extent of the value of collateral securing such indebtedness. Borrowings under our new revolving credit facility will be secured by a substantial portion of our assets.
Optional Redemption		We may redeem the notes in whole, at any time, or in part, from time to time, prior to maturity, at a redemption price that includes accrued and unpaid interest and a make-whole premium. See “Description of Notes — Optional Redemption” beginning on page S-118.

Covenants		We will issue the notes under an indenture with U.S. Bank National Association, as trustee. The covenants in the indenture include a limitation on liens and a restriction on sale-leaseback transactions. The covenants will generally not apply to ETP and its subsidiaries. Each covenant is subject to a number of important exceptions, limitations and qualifications that are described in “Description of Notes” under the heading “Covenants.”
Mandatory Offer to Repurchase		If we experience a change of control together with a rating decline, each as defined in the indenture, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase. See “Description of Notes — Covenants.”
Use of Proceeds		We anticipate using approximately $124 million of the net proceeds of this offering to repay all of the outstanding indebtedness under our existing revolving credit facility and approximately $1.45 billion of the net proceeds of this offering to repay indebtedness outstanding under our term loan facility. In addition, we anticipate using the remaining approximately $144 million of the net proceeds of this offering to fund a portion of the estimated cost to terminate interest rate swap agreements relating to these outstanding borrowings. We anticipate funding the remaining $14.3 million of estimated costs to terminate these interest rate swap agreements with borrowings under our new $200 million senior secured revolving credit facility, which we will enter into contemporaneously with the consummation of this offering and the repayment of outstanding indebtedness under our existing revolving credit facility. See “Use of Proceeds” and “Description of Other Indebtedness.”
Governing Law		The indenture and the notes provide that they will be governed by, and construed in accordance with, the laws of the state of New York.
Risk Factors		Investing in the notes involves risks. See “Risk Factors” beginning on page S-15 of this prospectus supplement and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the notes.
Original Issue Discount		The notes may be issued with original issue discount, or OID, for U.S. federal income tax purposes. If the notes are issued with OID, then such OID will accrue from the date of issuance of the notes and will be included as interest income in a U.S. holder’s gross income for U.S. federal income tax purposes in advance of receipt of the cash payments to which such income is attributable, regardless of such holder’s method of tax accounting. See “Certain United States Federal Income and Estate Tax Considerations — Tax Consequences to U.S. Holders — Stated Interest and OID on the Notes.”

														Four Months
		Nine Months Ended								Year Ended				Ended
		September 30,								December 31,				December 31,				Years Ended August 31,
		2009				2008				2008				2007				2007				2006
Statement of Operations Data:
Revenues:
Intrastate transportation and storage segment		$	1,589,298			$	4,862,641			$	5,634,604			$	1,254,401			$	3,915,932			$	5,013,224
Interstate transportation segment			203,349				176,663				244,224				76,000				178,663				—
Midstream segment			1,750,466				4,555,340				5,342,393				1,166,313				2,853,496				4,223,544
Eliminations			(540,075	)			(3,272,574	)			(3,568,065	)			(664,522	)			(1,562,199	)			(2,359,256	)
Retail propane and other retail propane related segment			902,471				1,162,941				1,624,010				511,258				1,284,867				879,556
Other			6,004				13,675				16,201				5,892				121,278				102,028
Total revenues			3,911,513				7,498,686				9,293,367				2,349,342				6,792,037				7,859,096
Gross margin			1,648,233				1,761,442				2,355,287				675,688				1,713,831				1,290,780
Depreciation and amortization			239,626				200,922				274,372				75,406				191,383				129,636
Operating income			744,630				846,133				1,098,903				316,651				809,336				575,540
Interest expense, net of interest capitalized			(341,050	)			(261,297	)			(357,541	)			(103,375	)			(279,986	)			(150,646	)
Income before income tax expense			461,548				625,692				683,562				192,758				563,359				433,907
Income tax expense			5,773				6,600				3,808				9,949				11,391				23,015
Net income attributable to noncontrolling interest			152,893				266,614				304,710				90,132				232,608				303,752
Net income attributable to partners			302,882				352,478				375,044				92,677				319,360				107,140
Balance Sheet Data (at period end):
Current assets			858,411				1,779,940				1,180,995				1,403,796				1,050,578				1,302,735
Total assets			11,684,508				11,267,924				11,069,902				9,462,094				8,183,089				5,924,141
Current liabilities			882,387				1,322,535				1,208,921				1,241,433				932,815				1,020,787
Long-term debt, less current maturities			7,740,135				7,181,710				7,190,357				5,870,106				5,198,676				3,205,646
Total equity			2,753,663				47,969				2,339,316				2,091,156				1,835,300				1,484,878

														Four Months
		Nine Months Ended								Year Ended				Ended
		September 30,								December 31,				December 31,				Years Ended August 31,
		2009				2008				2008				2007				2007				2006
Other Financial Data:
Cash flow provided by operating activities			721,421				908,837				1,143,720				208,635				1,006,320				502,928
Cash flow used in investing activities			(1,225,719	)			(1,439,741	)			(2,015,585	)			(995,943	)			(2,158,090	)			(1,244,406	)
Cash flow provided by financing activities			462,467				1,100,479				907,331				766,515				1,202,916				734,223
Capital expenditures:
Maintenance (accrual basis)			71,766				75,931				140,966				48,998				89,226				51,826
Growth (accrual basis)			534,696				1,532,458				1,921,679				604,371				998,075				677,861
Acquisition			6,244				62,002				84,783				337,092				90,695				586,185

														Four Months
		Nine Months Ended								Year Ended				Ended
		September 30,								December 31,				December 31,				Years Ended August 31,
		2009				2008				2008				2007				2007				2006
Statement of Operations Data:
Equity in earnings of affiliates		$	370,195			$	441,299			$	551,835			$	168,547			$	435,247			$	204,987
Selling, general and administration expense			(3,608	)			(4,523	)			(6,453	)			(2,875	)			(8,496	)			(55,374	)
Interest expense			(56,728	)			(69,527	)			(91,822	)			(37,071	)			(104,405	)			(36,773	)
Losses on non-hedged interest rate derivatives			(7,954	)			(13,759	)			(77,435	)			(27,670	)			(1,952	)			—
Losses on extinguishment of debt			—				—				—				—				—				(5,060	)
Other, net			329				(993	)			(1,056	)			(8,128	)			(405	)			(638	)
Net income		$	302,882			$	352,478			$	375,044			$	92,677			$	319,360			$	107,140
Balance Sheet Data (at period end):
Current assets			1,759				100,842				684				11,694				25,783				1,899
Total assets			1,653,787				1,800,706				1,671,339				1,630,940				1,537,875				668,488
Current liabilities			74,831				39,741				61,419				27,978				10,507				5,331
Long-term debt, less current maturities			1,573,923				1,672,026				1,571,642				1,572,643				1,571,500				616,291
Cash Flow Data:
Cash flow provided by operating activities		$	349,402			$	329,150			$	436,819			$	77,360			$	239,777			$	110,554
Cash flow provided by financing activities			(349,402	)			(229,192	)			(436,799	)			(85,919	)			968,689				16,142
Distributable Cash Flow:
Distributions related to period expected from ETP:
Limited partner interests			167,580				166,018				221,878				70,313				199,221				91,127
General partner interests			14,588				12,740				17,322				5,110				13,676				8,090
Incentive distribution rights			255,808				219,298				298,575				85,775				222,353				71,513
Total distributions related to period expected from ETP			437,976				398,056				537,775				161,198				435,250				170,730
ETE related expenses			(2,205	)			(5,600	)			(7,007	)			(11,288	)			(10,343	)			(3,404	)
Interest expense, net of amortization of financing costs, interest income, and realized gains and losses on interest rate derivatives			(70,342	)			(74,218	)			(97,654	)			(34,748	)			(100,933	)			(35,279	)
Distributable Cash Flow		$	365,429			$	318,238			$	433,114			$	115,162			$	323,974			$	132,047

														Four Months
		Nine Months Ended								Year Ended				Ended
		September 30,								December 31,				December 31,				Years Ended August 31,
		2009				2008				2008				2007				2007				2006
Reconciliation of Net income to Distributable Cash Flow:
Net income		$	302,882			$	352,478			$	375,044			$	92,677			$	319,360			$	107,140
Adjustments to derive Distributable Cash Flow:
Equity in income of unconsolidated affiliates			(370,195	)			(441,299	)			(551,835	)			(168,547	)			(435,247	)			(204,987	)
Distributions related to period expected from ETP			437,976				398,056				537,775				161,198				435,251				170,730
Amortization included in interest			5,236				2,255				5,076				1,006				2,630				1,151
Unrealized (gains) losses on non-hedged interest rate swaps			(10,885	)			6,734				66,231				28,805				1,952				—
Other non-cash			415				14				823				23				28				58,013
Distributable Cash Flow		$	365,429			$	318,238			$	433,114			$	115,162			$	323,974			$	132,047
Reconciliation of Cash flow provided by operating activities to Distributable Cash Flow:
Cash flow provided by operating activities		$	349,402			$	329,150			$	436,819			$	77,360			$	239,777			$	110,554
Adjustments to derive Distributable Cash Flow:
Distributions related to period expected from ETP			437,976				398,056				537,775				161,198				435,251				170,730
Cash distributions received from ETP			(425,938	)			(399,295	)			(535,342	)			(110,878	)			(360,602	)			(149,283	)
Deferred income taxes			649				—				—				—				—				—
Net changes in operating assets and liabilities			3,340				(9,673	)			(6,138	)			(12,518	)			9,548				46
Distributable Cash Flow		$	365,429			$	318,238			$	433,114			$	115,162			$	323,974			$	132,047

 

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our partnership could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in the notes. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

 

Risks Related to the Notes

 

The notes will be effectively subordinated to liabilities and indebtedness of our subsidiaries and subordinated to any of our future secured indebtedness to the extent of the assets securing such indebtedness.

 

We do not own any operating assets. Our principal assets consist of approximately 62.5 million common units of ETP in addition to the incentive distribution rights and general partner interest of ETP, and we own these incentive distribution rights and general partner interest through a wholly owned subsidiary. Initially, none of our subsidiaries will guarantee our obligations with respect to the notes. Creditors of our subsidiaries that do not guarantee the notes will have claims with respect to the assets of those subsidiaries that rank effectively senior to claims of the holders of the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors must be satisfied prior to making any such distribution or payment to us in respect of our direct or indirect equity interests in such subsidiaries. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. Also, there are federal and state laws that could invalidate any guarantee of our subsidiary or subsidiaries that guarantee the notes. If that were to occur, the claims of creditors of a guaranteeing subsidiary would also rank effectively senior to the notes, to the extent of the assets of that subsidiary. Furthermore, such subsidiaries are not prohibited under the indenture from incurring additional indebtedness.

 

In addition, holders of any of our secured indebtedness would have claims with respect to the assets constituting collateral for such indebtedness that are prior to the claims of the holders of the notes. Borrowings under our revolving credit facility will be secured by a substantial portion of our assets and we may have additional secured indebtedness in the future. In the event of a default on any secured indebtedness or our bankruptcy, liquidation or reorganization, our assets would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the notes. Accordingly, any such secured indebtedness would effectively rank senior to the notes to the extent of the value of the collateral securing the indebtedness. While the indenture governing the notes places some limitations on our ability to create liens, there are significant exceptions to these limitations that will allow us to secure some kinds of indebtedness without equally and ratably securing the notes. To the extent the value of the collateral is not sufficient to satisfy the secured indebtedness, the holders of that indebtedness would be entitled to share with the holders of the notes and the holders of other claims against us with respect to our other assets.

 

Neither ETP nor any of its subsidiaries will guarantee the payment of the notes, and our ability to pay principal and interest on the notes is dependent upon ETP having sufficient cash available for distributions on its common units and incentive distribution rights after satisfaction of the debt obligations of ETP and its subsidiaries.

 

Neither ETP nor any of its subsidiaries will guarantee our obligations with respect to the notes. Our ability to pay principal and interest on the notes is dependent upon our receipt of cash distributions from ETP in respect of our ETP common units and incentive distribution rights of ETP, which cash distributions are subject to the priority rights of creditors of ETP and its subsidiaries. Accordingly, creditors of ETP and its subsidiaries will have claims, with respect to the assets of ETP and its subsidiaries, that rank effectively senior to the notes. In the event of any distribution or payment of assets of ETP and its subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of the creditors

of ETP and its subsidiaries must be satisfied prior to ETP making any such distribution to us in respect of our direct or indirect equity interests in ETP. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts distributed to us to make payments in respect of the notes. As of September 30, 2009, the notes would have been effectively subordinated to approximately $6.2 billion of outstanding indebtedness of ETP and its subsidiaries. Furthermore, neither ETP nor any of its subsidiaries are subject to any provisions of the indenture, and therefore the indenture does not prohibit ETP or any of its subsidiaries from incurring additional indebtedness.

 

We may incur substantially more debt, which could further exacerbate the risks related to our indebtedness.

 

Assuming we had completed this offering on September 30, 2009, ETE would have had approximately $1.76 billion of indebtedness outstanding and our subsidiaries, including ETP and its subsidiaries, would have had approximately $6.2 billion of indebtedness outstanding. We and our subsidiaries, including ETP, may incur substantial additional indebtedness in the future, including pursuant to our revolving credit facility. The terms of the indenture do not prohibit us from doing so. If we incur any additional indebtedness, including trade payables, that ranks equally with the notes, the holders of that debt will be entitled to share ratably with you in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of our partnership. This may have the effect of reducing the amount of proceeds paid to you. If new debt is added to our current debt levels, the related risks that we now face could intensify. See “Description of Notes” and “Description of Other Indebtedness.”

 

We may not be able to repurchase the notes upon a change of control.

 

Upon the occurrence of a change of control trigger event, we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control trigger event because we may not have sufficient funds. Further, we may be contractually restricted under the terms of our revolving credit facility or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase your notes unless we are able to refinance or obtain waivers under our credit facilities. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross-default under our revolving credit facility. Our revolving credit facility provides that a change of control, as defined in such agreement, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and, if such debt is not paid, to enforce security interests in the collateral securing such debt, thereby limiting our ability to raise cash to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions.

 

In addition, the change of control provisions in the indenture may not protect you from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction.

 

The notes may be issued with original issue discount, in which case you generally will be required to accrue income before you receive cash attributable to the original issue discount on the notes. Additionally, in the event we enter into bankruptcy, you may not have a claim for all or a portion of any unamortized amount of the original discount on the notes.

 

The notes may be issued with original issue discount, or OID, for U.S. federal income tax purposes. If the notes are issued with OID and if you are a U.S. holder, you generally will be required to accrue OID on a current basis as ordinary income and pay tax accordingly, even before you receive cash attributable to that income and regardless of your method of tax accounting. For further discussion of the computation and reporting of OID, see “Certain United States Federal Income and Estate Tax Considerations — Tax Consequences to U.S. Holders — Stated Interest and OID on the Notes.”

 

Additionally, a bankruptcy court may not allow a claim for all or a portion of any unamortized amount of the OID on the notes.

Your ability to transfer the notes at a time or price you desire may be limited by the absence of an active trading market, which may not develop.

 

The notes are a new issue of securities for which there is no established public market. Although we have registered the offer and sale of the notes under the Securities Act of 1933, we do not intend to apply for the listing of the notes on any securities exchange or for the quotation of the notes in any automated dealer quotation system. In addition, although the underwriters have informed us that they intend to make a market in the notes, as permitted by applicable laws and regulations, they are not obligated to make a market in the notes, and they may discontinue their market making activities at any time without notice. An active market for the notes may not develop or, if developed, may not continue. In the absence of an active trading market, you may not be able to transfer the notes within the time or at the price you desire.

 

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.

 

We do not have any significant assets other than our partnership interests in ETP. As a result, our ability to make required payments on the notes depends on the performance of ETP and its subsidiaries and ETP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP.

 

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:

 

 

 

ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors of ETP’s general partner. Accordingly, we cannot guarantee that ETP will have sufficient available cash to pay a specific level of cash distributions to its partners.

 

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

 

A reduction in ETP’s distributions will disproportionately affect the amount of cash distributions to which we are entitled, which may adversely impact our ability to make required payments on the notes.

 

Our indirect ownership of 100% of the incentive distribution rights in ETP, through our ownership of equity interests in ETP 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 ETP 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 ETP 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 general partner interest in ETP and our ETP common units.

 

ETP’s consolidated debt level may limit the distributions we receive from ETP, our future financial and operating flexibility and our ability to make required payments on the notes.

 

As of September 30, 2009, ETP had approximately $6.2 billion of consolidated debt outstanding. ETP’s level of indebtedness affects its operations in several ways, including, among other things:

 

 

 

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service the notes or to repay them at maturity.

 

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash on hand as of the end of a fiscal quarter, adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:

 

 

Although our payment obligations to our unitholders are subordinate to our payment obligations to you, the value of our units may decrease with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, the value of our units may decrease and we may not be able to issue equity to recapitalize.

 

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes and our indebtedness under our credit facilities, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

 

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

 

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements, including our credit agreement and the indenture that will govern the notes. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our credit facilities restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations then due. See “Description of Other Indebtedness” and “Description of Notes.”

 

ETP is not prohibited from competing with us.

 

Neither our partnership agreement nor the partnership agreement of ETP prohibits ETP from owning assets or engaging in businesses that compete directly or indirectly with us. Additionally, ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, 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.

 

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 September 30, 2009, we had approximately $7.79 billion of consolidated debt, of which approximately $5.73 billion was at fixed interest rates and approximately $2.06 billion was at variable interest rates. We have entered interest rate swaps for a total notional amount of $2.00 billion, resulting in a net amount of $0.06 billion of variable-rate debt at September 30, 2009. 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.

 

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 indirect owners of our general partner may be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and indirect owners over our business activities, including our cash distributions, 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.

 

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

 

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. For further discussion of the importance of our treatment as a partnership for federal income tax purposes and the implications that would result from our treatment as a corporation in any taxable year, please read the risk factor below entitled “Our tax treatment depends on our continuing 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 we or ETP were to be treated as a corporation or if we or ETP becomes subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for payment of principal and interest on the notes.”

If ETP GP withdraws or is removed as ETP’s general partner, then we would lose control over the management and affairs of ETP, the risk that we would be deemed an investment company under the Investment Company Act 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 common units (including units held by ETP GP and its affiliates). Currently, ETP GP and its affiliates own approximately 33% of ETP’s outstanding common units.

 

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.

 

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

 

At September 30, 2009, our consolidated balance sheet reflected $765.9 million of goodwill and $401.2 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.

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

 

The partnership agreement of ETP allows ETP to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP will have the following effects:

 

 

The payment of distributions on any additional units issued by ETP 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 meet our obligations, including obligations under the notes.

 

Our tax treatment depends on our continuing 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 we or ETP were to be treated as a corporation or if we or ETP becomes subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for payment of principal and interest on the notes.

 

Despite the fact that we and ETP are limited partnerships under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. If we are so treated, 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. Because a tax would then be imposed upon us as a corporation, our cash available for payment of principal and interest on the notes would be substantially reduced. Therefore, treatment of us or ETP 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 for any taxable year for which the statute of limitations remains open or for any future taxable year, 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.

 

Moreover, 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, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Specifically, federal income tax legislation has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. We or ETP are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted.

 

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.

 

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.

 

Affiliates of our general partner are not prohibited from competing with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Enterprise GP Holdings L.P. currently has a 40.6% non-controlling equity interest in our general partner. Enterprise GP Holdings L.P. and its subsidiaries own and operate a North American midstream energy business that competes with us and ETP with respect to ETP’s natural gas midstream business.

 

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, which may permit them to favor their own interests to the detriment of us.

 

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, 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 our interests. These conflicts include, among others, the following:

 

 

 

Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available 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:

 

 

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.

 

ETP may not be able to obtain funding on acceptable terms or at all under its revolving credit facility or otherwise because of the deterioration of the credit and capital markets. This may hinder or prevent ETP from meeting future capital needs.

 

Global financial markets have been, and continue to be, disrupted and volatile due to a variety of factors, including significant write-offs in the financial services sector and the current weak economic conditions. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. In particular, as a result of concerns

about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, ETP cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, ETP may be unable to meet its obligations as they come due or ETP may be required to post collateral to support its obligations. Moreover, without adequate funding, ETP may be unable to execute its growth strategy, complete future acquisitions or announced and future pipeline construction projects, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on ETP’s revenues and results of operations.

 

As of September 30, 2009, ETP had approximately $6.2 billion of consolidated debt outstanding. A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuances of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under ETP’s revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.

 

Many of ETP’s customers’ drilling activity levels and spending for transportation on ETP’s pipeline system may be impacted by the current deterioration in commodity prices and the credit markets.

 

Many of ETP’s customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of ETP’s customers’ equity values have substantially declined. The combination of a reduction of cash flow resulting from recent declines in natural gas prices, a reduction in borrowing base under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in ETP’s customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on ETP’s pipeline systems. A significant reduction in drilling activity could have a material adverse effect on ETP’s operations.

 

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. The current tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s customers. Any substantial increase in the nonpayment and nonperformance by ETP’s customers could have a material adverse effect on ETP’s results of operations and operating cash flows.

 

ETP is exposed to claims by third parties related to the claims that were previously brought against ETP by the Federal Energy Regulatory Commission, or FERC.

 

On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties, which we refer to as the Order and Notice, that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from its commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the Natural Gas Act, or NGA. The FERC alleged that ETP violated this rule by artificially

suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations, by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. The FERC specified that it was also seeking to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at market-based prices. In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

 

On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against it and on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement resolves all outstanding FERC claims against ETP and provides that ETP will make a $5 million payment to the federal government and will establish a $25 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against the funds, including existing litigation claims as well as any new claims that may be asserted against this fund. Any unused portion of the fund shall be paid to the United States Treasury. The administrative law judge appointed by the FERC will determine the validity of any third party claim against this fund. Any party who receives money from this fund will be required to waive all claims against ETP related to this matter. The claims of third parties that do not elect to pursue the fund are unaffected. Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law. In addition, the settlement agreement specifies that ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with its alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

 

In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETP alleging damages related to these matters. In this regard, several natural gas producers and a natural gas marketing company have initiated legal proceedings in Texas state courts against us and ETP for claims related to the FERC claims. These suits contain contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits against us and ETP contains an additional allegation that we and ETP transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. In one of these cases, the Texas Supreme Court ruled on July 3, 2009 that the state district court erred in ruling that a plaintiff was entitled to pre-arbitration discovery and therefore remanded to the state district court with a direction to rule on our original motion to compel arbitration pursuant to the terms of the arbitration clause in a natural gas contract between us and the plaintiff. This plaintiff has filed a motion with the Texas Supreme Court requesting a rehearing of the ruling.

 

In February 2008, ETP was served with a complaint from an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. ETP filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted ETP’s motion for summary judgment on that issue. This action is currently on appeal before the First Court of Appeals, Houston, Texas.

In October 2007, a consolidated class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act, or CEA. It is further alleged that during the class period from December 29, 2003 to December 31, 2005, ETP had 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, in order to benefit its natural gas physical and financial trading positions, and that ETP intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, ETP filed a motion to dismiss the complaint. On March 26, 2009, the court issued an order dismissing the complaint, with prejudice, for failure to state a claim. On April 9, 2009, the plaintiffs moved for reconsideration of the order dismissing the complaint, and on August 26, 2009, the court denied the plaintiffs’ motion for reconsideration. On September 28, 2009, these decisions were appealed by the plaintiffs to the United States Court of Appeals for the 5th Circuit, and the appeal is currently in briefing stage before the court.

 

In March 2008, a second class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit its own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On March 26, 2009, the court issued an order dismissing the complaint. The court found that the plaintiffs failed to state a claim on all causes of action and for antitrust injury, but granted leave to amend. On April 23, 2009, the plaintiffs filed a motion for leave to amend to assert a claim for common law fraud and attached a proposed amended complaint as an exhibit. ETP opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted ETP’s motion to dismiss the complaint. On September 10, 2009, this decision was appealed by the plaintiff to the United States Court of Appeals for the 5th Circuit, and the appeal is currently in briefing stage before the court.

 

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such expenses are incurred. ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, ETP increased its accrual for these matters to $30.0 million in the aggregate as of September 30, 2009. While ETP expects the after-tax cash impact of the settlement to be less than $30.0 million due to tax benefits resulting from the portion of the accrual that is used to satisfy third-party claims, ETP may not be able to realize such tax benefits. Although this accrual covers the $25.0 million required by the settlement agreement to be applied to resolve third-party claims, including the existing third-party litigation described above, it is possible that the amount ETP becomes obliged to pay to resolve third-party litigation related to these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of the new accrual related to these matters. In accordance with applicable accounting standards, ETP will review the amount of its accrual related to these matters as developments related to these matters occur and ETP will adjust its accrual if it determines that it is probable that the amount it may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of its accrual for

these matters. As its 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 ETP’s cash available to service its indebtedness 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, ETP may experience a material adverse impact on its results of operations and its liquidity.

 

The profitability of ETP’s midstream and intrastate transportation and storage operations are 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 is 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 ETP’s Houston pipeline system, which we refer to as the HPL System, ETP purchases natural gas from producers at the wellhead and then gathers and delivers the natural gas to pipelines where ETP typically resells the natural gas under various arrangements, including sales at index prices. Generally, the gross margins ETP realizes under these arrangements decrease in periods of low natural gas prices.

 

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 British thermal unit, or 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, ETP processes the gas for a fee. If recoveries are less than those guaranteed the producer, ETP 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 year ended December 31, 2008, the NYMEX settlement price for the prompt month contract ranged from a high of $13.11 per million Btu, or MMBtu, to a low of $6.47 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during ETP’s year ended December 31, 2008 ranged from a high of approximately $1.96 per gallon to a low of approximately $0.66 per gallon.

 

ETP’s Oasis pipeline, East Texas pipeline, ET Fuel System and HPL System receive fees for transporting natural gas for their 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, among other factors, 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 risk management mechanisms. 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 derivatives 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 ETP’s 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 Pipeline Company, LLC, or Transwestern, derives a significant portion of its revenue from charging its customers for reservation of capacity, which 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 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 is 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. We cannot assure you that ETP’s 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, both of which would limit ETP’s ability to fully execute its growth strategy. Inability to execute its growth strategy may materially adversely impact ETP’s results of operations.

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 additional 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. ETP currently has several major expansion and new build projects planned or underway, including the Fayetteville Express pipeline and the Tiger pipeline. A variety of factors outside ETP’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors has resulted in, and may continue to result in, increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s results of operations and cash flows. 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. In addition, 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. In this regard, ETP may construct facilities to capture anticipated future growth in natural gas 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.

 

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 year ended December 31, 2008, XTO Energy Inc., EnCana Oil and Gas (USA), Inc., Sandridge Energy Inc. and ConocoPhillips Company supplied ETP with approximately 75% of the Southeast Texas System’s natural gas supply. For ETP’s year ended December 31, 2008, XTO Energy Inc., Chesapeake Energy Marketing, Inc., EnCana Oil and Gas (USA), Inc. and EOG Resources, Inc. supplied ETP with approximately 75% 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 through its pipelines.

 

ETP has nine- and ten-year fee-based transportation contracts with XTO Energy, Inc., or XTO, that terminate in 2013 and 2017, respectively, pursuant to which XTO has committed to transport certain minimum volumes of natural gas on pipelines in ETP’s ET Fuel System. 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 that terminate in 2012 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 or TXU Shipper to fulfill their contractual obligations under these contracts

could have a material adverse effect on ETP’s and our 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.

 

The major shippers on ETP’s intrastate transportation pipelines include XTO, EOG Resources, Inc., Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. and Quicksilver Resources, Inc. These shippers have long-term contracts that have remaining terms of up to fifteen years. The failure of these shippers to fulfill their contractual obligations could have a material adverse effect on ETP’s and our 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.

 

With respect to ETP’s interstate transportation operations, Midcontinent Express Pipeline, LLC, or MEP, has secured predominantly 10-year firm transportation contracts from a small number of major shippers for all of the initial 1.5 Bcf/d of capacity on the Midcontinent Express pipeline. MEP has also secured firm transportation commitments for an additional 0.3 Bcf/d of capacity on the Midcontinent Express pipeline, which expansion is subject to regulatory approval. Fayetteville Express Pipeline, LLC, or FEP, has secured a binding 10-year commitment for approximately 1.85 Bcf/d of firm transportation service on the 2.0 Bcf/d Fayetteville Express pipeline project. In connection with ETP’s Tiger pipeline project, ETP has entered into agreements with multiple shippers that provide for 10- and 15-year commitments for firm transportation capacity of all of the total initial capacity of at least 2.0 Bcf/d. The failure of these key shippers to fulfill their contractual obligations could have a material adverse effect on ETP’s and our cash flow and results of operations if ETP were 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 the business and operations of ETP’s midstream and intrastate assets.

 

ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects its 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 East Texas pipeline, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than its currently approved rates ETP 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.

 

FERC has adopted new market-monitoring and annual and quarterly reporting regulations, which regulations are applicable to many intrastate pipelines as well as other entities that are otherwise not subject to FERC’s NGA jurisdiction, such as natural gas marketers. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. These regulations may result in administrative burdens and additional compliance costs for ETP.

 

ETP holds transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, ETP is subject to FERC requirements related to use of the interstate capacity. Any failure on ETP’s part to comply with the FERC’s regulations or orders could result in the imposition of administrative, civil and criminal penalties.

 

ETP’s intrastate transportation and storage operations are subject to state regulation in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, the states in which ETP operates these types of natural gas

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

 

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

 

ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the natural gas storage facilities of the ET Fuel System and 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 TRRC-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, or the Pipeline Safety Act, 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 the Pipeline Safety 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 laws and regulations could result in the imposition of administrative, civil and criminal remedies.

 

ETP’s interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services.

 

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. NGA-jurisdictional natural gas companies must charge rates that are deemed just and reasonable by FERC. The rates charged by natural gas companies are generally required to be on file with FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. ETP also may be limited by the terms of negotiated rate agreements from seeking future rate increases, or constrained by competitive factors from charging its FERC-approved maximum just and reasonable rates. Further, rates must, for the most part, be cost-based and FERC may, on a prospective basis, order refunds of amounts collected under rates that have been found by FERC to be 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 a new general rate case until

October 2011. However, shippers (other than shippers that have agreed, as parties to the Stipulation and Agreement, not to challenge Transwestern’s tariff rates through the remaining term of the settlement) may challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates absent shipper complaint.

 

Most of the rates to be paid by the initial shippers on the Midcontinent Express pipeline are established pursuant to long-term, negotiated rate transportation agreements. Other prospective shippers on Midcontinent Express pipeline that elect not to pay a negotiated rate for service may opt instead to pay a cost-based recourse rate established by FERC as part of Midcontinent Express pipeline’s certificate of public convenience and necessity. Negotiated rate agreements generally provide a degree of certainty to the pipeline and shipper as to a fixed rate during the term of the relevant transportation agreement, but such agreements can limit the pipeline’s future ability to collect costs associated with construction and operation of the pipeline that might be higher than anticipated at the time the negotiated rate agreement was entered. FERC applications for authorization to construct, own and operate the Fayetteville Express pipeline and the Tiger pipeline were filed on June 15, 2009 and August 31, 2009, respectively. On December 17, 2009, the FERC issued an order granting authorization to construct, own and operated the Fayetteville Express pipeline, subject to certain conditions. While FEP has accepted the FERC’s certificate authorization, this order is subject to possible rehearing and judicial review. FERC has not yet determined whether the Tiger pipeline should be granted the requested authority. ETP cannot predict if, or when and with what conditions, FERC authorization for the Tiger pipeline will be granted.

 

Any successful challenge to the rates of ETP’s interstate natural gas companies, whether brought by complaint, protest or investigation, could reduce its revenues associated with providing transportation services on a prospective basis. We and ETP cannot assure you that ETP’s interstate pipelines will be able to recover all of their 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. It is currently FERC’s policy to 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 FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates its interstate pipelines charge for interstate natural gas transportation. The application of that policy remains subject to future refinement or change by FERC. With regard to rates charged and collected by Transwestern, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is generally not subject to challenge prior to the expiration of its settlement agreement in 2011.

 

The interstate pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect their business and operations.

 

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

 

 

 

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

 

ETP must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of its business plans. For example, in order to carry out its plan to construct the Fayetteville Express and Tiger pipelines ETP must, among other things, file and support before FERC NGA Section 7(c) applications for certificates of public convenience and necessity to build, own and operate such facilities. Although the FERC has authorized the construction and operation of the Fayetteville Express pipeline, subject to certain conditions, this order is subject to possible rehearing and judicial review. Thus, we and ETP cannot guarantee that FERC will authorize construction and operation of the Tiger pipeline. Moreover, there is no guarantee that, if granted, certificate authority for the Tiger pipeline will be granted in a timely manner or will be free from potentially burdensome conditions. Similarly, ETP was required to obtain from FERC a certificate of public convenience and necessity to build, own and operate the Midcontinent Express pipeline. In addition, MEP subsequently amended its request to expand the capacity of its pipeline. FERC has granted MEP certificate authority for this expansion project.

 

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 NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC possesses similar authority under the NGPA.

 

Finally, neither we nor ETP can give any assurance regarding the likely future regulations under which ETP will operate its interstate pipelines or the effect such regulation could have on its 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 ETP’s 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 ETP’s operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the 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 of the underlying risk inherent to its operations. Environmental laws provide for joint and several strict liability for cleanup costs incurred to address discharges or releases of petroleum hydrocarbons or wastes on, under, or from ETP’s properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by ETP’s predecessors. Private parties, including the owners of properties through which ETP’s gathering systems pass or facilities where its petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. The total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations is approximately $8.7 million, and such activities are expected to continue through 2018.

Changes in environmental laws and regulations occur frequently, and changes that result in significantly more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For example, the EPA in 2008 lowered the federal ozone standard from 0.08 parts per million to 0.075 parts per million, which will require the environmental agencies in states with areas that do not currently meet this standard to adopt new rules to further reduce NOx and other ozone precursor emissions. ETP has previously been able to satisfy the more stringent NOx emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no guarantee that the changes ETP may have to make in the future to meet the new ozone standard or other evolving standards will not require it to incur costs that could be material to its operations.

 

In response to scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere and other changes to the global climate, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA.” ACESA would establish an economy-wide “cap-and-trade” program to reduce domestic emissions of greenhouse gases by 17% from 2005 levels by 2020 and just over 80% by 2050. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to major sources of greenhouse gas emissions, including producers of NGLs (that is, gas processing plants), local natural gas distribution companies and certain industrial facilities, so that such sources could continue to emit greenhouse gases into the atmosphere. The cost of these allowances would be expected to escalate significantly over time. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Senate bill contains many of the same elements as ACESA. Although it is not possible at this time to predict when the Senate might pass its own climate change legislation or how any bill passed by the Senate would ultimately be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require ETP to incur increased operating costs and could adversely affect demand for the natural gas and NGL products and services ETP provides.

 

In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through regional greenhouse gas cap and trade programs. These cap and trade programs require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to hold emission allowances for the amounts of greenhouse gases that they emit or would be produced as a result of the combustion of the fuels they produce. Regulated entities with insufficient allowances are required to acquire enough emission allowances from other allowances to make up for any deficits. While the details of many of these regional programs are still being worked out and while any federal legislation that is passed would be expected to preempt the state or regional greenhouse gas regulatory programs to some extent, ETP could be required to purchase allowances under these regional programs, either for greenhouse gas emissions resulting from ETP’s operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas) that ETP processes.

 

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, EPA was required to determine whether greenhouse gas emissions from mobile sources such as cars and trucks posed an endangerment to human health and the environment. On December 7, 2009, the EPA announced its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA proposed two sets of regulations in anticipation of finalizing its endangerment finding: one to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take the EPA several years to impose regulations limiting emissions of greenhouse gases from stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting by March

2011 of calendar year 2010 greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including natural gas liquids fractionators and local natural gas distribution companies. As with the regional greenhouse gas regulatory programs, any federal greenhouse gas legislation is expected to prevent the EPA from regulating greenhouse gases under existing Clean Air Act regulatory programs to some extent, but if Congress fails to pass greenhouse gas legislation, the EPA is expected to continue its announced regulatory actions. Any limitation on emissions of greenhouse gases from ETP’s equipment and operations could require ETP to incur significant costs to reduce emissions of greenhouse gases associated with ETP’s operations or acquire allowances at the prevailing rates in the marketplace.

 

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 Transwestern pipeline and the Midcontinent Express pipeline compete with, and upon completion the Fayetteville Express pipeline will compete with, 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 ETP’s 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 ETP’s 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. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

 

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 ETP’s processing plants 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 gas 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 year ended December 31, 2008, approximately 27.3% 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.” Through September 30, 2009, a total of $47.9 million of capital costs and $25.7 million of operating and maintenance costs have been incurred for pipeline integrity testing, including $24.6 million of capital costs and $12.6 million of operating and maintenance costs during the first nine months of 2009. 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, ETP’s 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 unseasonably cold or hot periods or dry weather conditions that 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.

 

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 us.

 

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 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 2008, ETP purchased approximately 50.7%, 15.0% and 14.9% of its propane from Enterprise Products Operating L.P., or Enterprise, Targa Liquids and M.P. Oils, Ltd., respectively. Enterprise is a subsidiary of Enterprise GP Holdings L.P., or Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding common units and a 40.6% non-controlling equity interest in our general partner. Titan Energy Partners, L.P., or 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.

 

We expect to receive net proceeds of approximately $1.72 billion from the sale of notes offered hereby, after deducting the underwriters’ discount and estimated offering expenses.

 

We anticipate using approximately $124 million of the net proceeds of this offering to repay all of the outstanding indebtedness under our existing revolving credit facility and approximately $1.45 billion of the net proceeds of this offering to repay all indebtedness outstanding under our term loan facility. In addition, we anticipate using the remaining approximately $144 million of the net proceeds of this offering to fund a portion of the estimated cost to terminate interest rate swap agreements relating to these outstanding borrowings. We anticipate funding the remaining $14.3 million of estimated costs to terminate these interest rate swap agreements with borrowings under our new $200 million senior secured revolving credit facility, which we will enter into contemporaneously with the consummation of this offering and the repayment of outstanding indebtedness under our existing revolving credit facility.

 

As of December 31, 2009, there was an aggregate of approximately $124 million of borrowings outstanding under our existing revolving credit facility and an aggregate of approximately $1.45 billion of borrowings outstanding under our term loan facility. The weighted average interest rate on the total amount outstanding under our existing revolving credit and term loan facilities at December 31, 2009 was 1.94%. Our existing revolving credit facility matures on February 8, 2011 and our term loan facility matures on November 1, 2012.

 

The following table sets forth our consolidated cash and capitalization as of September 30, 2009 on:

 

 

The actual information in the table is derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, included in our Annual Report on Form 10-K for the year ended December 31, 2008, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, which are incorporated by reference in this prospectus supplement.

 

 

 

 

Currently, we have no separate operating activities apart from those conducted by ETP. The table below reflects our consolidated operations, including the operations of ETP and its consolidated subsidiaries, except as indicated below.

 

In January 2004, we combined the natural gas midstream and transportation operations of Energy Transfer Company, or ETC OLP, with the retail propane operations of Heritage Propane Partners, L.P., referred to as the Energy Transfer Transactions. In March 2004, Heritage changed its name to Energy Transfer Partners, L.P. Although Heritage was the surviving parent entity for legal purposes in the Energy Transfer Transactions, ETC OLP was the acquirer for accounting purposes. As a result, following the Energy Transfer Transactions in January 2004, the historical financial statements of ETC OLP for periods prior to the closing of the Energy Transfer Transactions became our historical financial statements. ETC OLP was formed on October 1, 2002 and has a December 31 year-end. ETC OLP’s predecessor entities had a December 31 year-end.

 

In November 2007, we changed our fiscal year end from August 31 to December 31 and, in connection with such change, we have reported financial results for a four-month transition period ended December 31, 2007.

 

For periods prior to 2009, certain prior period financial statement amounts have been reclassified to conform to the 2009 presentation. These changes had no impact on net income or total equity, with the exception of changes to the presentation of noncontrolling interest resulting from the adoption of Accounting Standards Codification 810-10-65, which resulted in (i) the reclassification of noncontrolling (minority) interest from liabilities to a separate component of equity in our consolidated balance sheet, (ii) the reclassification of minority interest expense to net income attributable to noncontrolling interest in our consolidated statement of operations, and (iii) the reclassification of distributions to minority interests between cash flow from operating activities and cash flow from financing activities in our consolidated statement of cash flows.

 

The selected historical financial data should be read in conjunction with the consolidated financial statements of Energy Transfer Equity, L.P., incorporated by reference from each of our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The amounts in the table below, except per unit data, are in thousands.