Filed Pursuant to Rule 424(b)(5)
Registration No. 333-147990

 

 

 

PROSPECTUS SUPPLEMENT TO PROSPECTUS DATED DECEMBER 11, 2007

 

 

Energy Transfer Partners, L.P.

 

6,000,000 Common Units
Representing Limited Partner Interests

 

 

 

 

We are selling 6,000,000 common units representing limited partner interests. Our common units trade on the New York Stock Exchange under the symbol “ETP.” The last reported sales price of our common units on the NYSE on January 21, 2009 was $35.11 per common unit.

 

The underwriters have a 30-day option to purchase a maximum of 900,000 additional common units to cover over-allotments.

 

Investing in our common units involves risks. See “Risk Factors” beginning on page S-13 of this prospectus supplement and page 4 of the accompanying prospectus.

 

 

Delivery of the common units will be made on or about January 27, 2009.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

Joint Book-Running Managers

 

 

 

Co-Managers

 

 

The date of this prospectus supplement is January 22, 2009

 

TABLE OF CONTENTS

 

PROSPECTUS SUPPLEMENT

 

 

PROSPECTUS

 

 

 

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus or any free writing prospectus prepared by us or on our behalf. We have not authorized anyone to provide you with additional or different information. We are not making an offer to sell our common units in any jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this document or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since these dates.

 

We provide information to you about this offering of our common units in two separate documents that are bound together: (1) this prospectus supplement, which describes the specific details regarding this offering, and (2) the accompanying prospectus, which provides general information, some of which may not apply to this offering. Generally, when we refer to this “prospectus,” we are referring to both documents combined. If information in this prospectus supplement is inconsistent with the accompanying prospectus, you should rely on this prospectus supplement.

 

You should carefully read this prospectus supplement and the accompanying prospectus, including the information incorporated by reference in the prospectus, before you invest. These documents contain information you should consider when making your investment decision. None of Energy Transfer Partners, L.P., the underwriters or any of their respective representatives is making any representation to you regarding the legality of an investment in our common units by you under applicable laws. You should consult with your own advisors as to legal, tax, business, financial and related aspects of an investment in the common units.

 

 

SUMMARY

	•	In April 2007, we completed the 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 our capacity to transport natural gas produced from the Barnett Shale and the Bossier Sands to our Texoma pipeline and other pipeline interconnections. The Cleburne to Carthage pipeline is primarily a 42-inch diameter natural gas pipeline. In December 2007, we 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, we completed our 150-mile Southeast Bossier 42-inch natural gas pipeline, which we refer to as the Southeast Bossier pipeline. This pipeline connects our 42-inch Cleburne to Carthage pipeline and our 30-inch East Texas pipeline to our 30-inch Texoma pipeline. The Southeast Bossier pipeline has an initial throughput capacity of 900 million cubic feet per day, or MMcf/d, that can be increased to 1.3 Bcf/d with the addition of compression. The Southeast Bossier pipeline increases our takeaway capacity from the Barnett Shale and Bossier Sands and provides increased market access for natural gas produced in these areas.
	•	In July 2008, we completed our 36-inch Paris Loop natural gas pipeline expansion project in north Texas. This 135-mile pipeline initially provides us with an additional 400 MMcf/d of capacity out of the Barnett Shale, with an anticipated increase to 900 MMcf/d by the second quarter of 2009. The Paris Loop originates near Eagle Mountain Lake in northwest Tarrant County, Texas and connects to our Houston Pipe Line system near Paris, Texas.
	•	In August 2008, we completed an expansion of our Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub through the installation of 32 miles of 42-inch pipeline. This expansion, which we refer to as the Carthage Loop, added 500 MMcf/d of pipeline capacity from Cleburne to the Carthage Hub. We expect to increase the capacity of the Carthage Loop to 1.1 Bcf/d by adding compression to this pipeline, which capacity increase we expect to complete in the third quarter of 2009.
	•	In August 2008, we completed the first segment of our 36-inch 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, we completed our Southern Shale natural gas pipeline project, which consists of 31 miles of 36-inch pipeline that originates in southern Tarrant County, Texas and delivers natural gas

		to our 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, we completed our 36-inch 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 October 2007, we announced an expansion of our East Texas pipeline with the installation of 56 miles of 36-inch pipeline and the addition of 20,000 horsepower of compression. This expansion, which we refer to as the Katy expansion, will increase the capacity on the East Texas pipeline from approximately 700 MMcf/d to more than 1.1 Bcf/d and is expected to be in service by the end of the first quarter of 2009.
	•	In April 2008, we announced another pipeline expansion project, which we refer to as the Texas Independence Pipeline, that will consist of 148 miles of 42-inch pipeline connecting our ET Fuel System and North Texas System with our East Texas pipeline. The Texas Independence Pipeline will expand our 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. Construction of this pipeline is expected to begin in the first quarter of 2009, with completion expected in the third quarter of 2009.

	•	We believe that the size and scope of our operations, our stable asset base and cash flow profile, and our investment grade status will be significant positive factors in our efforts to obtain new debt or equity financing in light of current market conditions, as evidenced by our recent debt offering discussed below.
	•	Our experienced management team has an established reputation as highly-effective, strategic operators within our operating segments. In addition, our management team is motivated to effectively and efficiently manage our business operations through performance-based incentive compensation programs and through ownership of a substantial equity position in Energy Transfer Equity, L.P., the entity that indirectly owns our general partner and therefore benefits from incentive distribution payments we make to our general partner.

Public common units			59.3	%
General partner interest			2.0	%
Common units owned by Energy Transfer Equity			38.7	%
			100.0	%

(1)		Includes approximately 495,000 common units owned by management of Energy Transfer Partners, L.P.

Common units offered		6,000,000 common units
		6,900,000 common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		158,102,554 common units, or 159,002,554 common units if the underwriters exercise in full their option to purchase an additional 900,000 common units.
Use of proceeds		We will receive approximately $200 million from the sale of the 6,000,000 common units offered hereby, including our general partner’s proportionate capital contribution and after deducting underwriting discounts and commissions, estimated offering expenses, and giving effect to the reimbursement of expenses by the underwriters. We will use the net proceeds from the offering to repay approximately $200 million outstanding under our revolving credit facility. We expect to use some of the increased availability under the revolving credit facility to finance capital expenditures and other growth projects.
		We will use any net proceeds from the underwriters’ exercise of their option to purchase additional common units to repay additional borrowings outstanding under our revolving credit facility. Please read “Use of Proceeds.”
Cash distributions		Under our partnership agreement, we must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. We declared a quarterly distribution for our third quarter of 2008 of $0.894 per common unit, or $3.575 on an annualized basis. We paid this cash distribution on November 14, 2008 to unitholders of record at the close of business on November 10, 2008.
Limited call right		If at any time our affiliates own more than 80% of our outstanding units, our general partner has the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units. Management and other affiliates of our general partner currently own approximately 41.4% of our common units on a fully diluted basis.
Limited voting rights		Our general partner manages and operates us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its officers or directors. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including units owned by our general partner and its affiliates, voting together as a single class. Management and other affiliates of our general partner currently own approximately 41.4% of our outstanding common units. This ownership level will enable our general partner and these affiliates to prevent our general partner’s involuntary removal.

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed to you with respect to that period. Please read “Material Tax Considerations” in this prospectus supplement for the basis of this estimate.
Material tax consequences		For a discussion of other material federal income tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Income Tax Considerations” in the accompanying prospectus.
Exchange listing		Our common units are traded on the New York Stock Exchange under the symbol “ETP.”
Risk factors		There are risks associated with this offering and our business. You should consider carefully the risk factors beginning on page S-13 of this prospectus supplement and page 4 of the accompanying prospectus and the other risks identified in the documents incorporated by reference herein before making a decision to purchase common units in this offering.

		Nine Months Ended								Four Months Ended
		September 30,				August 31,				December 31,								Year Ended August 31,
		2008				2007				2007				2006				2007				2006				2005
Statement of Operations Data:
Revenues:
Midstream segment		$	4,555,340			$	2,245,313			$	1,166,313			$	905,392			$	2,853,496			$	4,223,544			$	3,246,772
Intrastate transportation and storage segment			4,862,641				3,105,079				1,254,401				1,195,871				3,915,932				5,013,224				2,608,108
Interstate transportation segment			176,663				178,663				76,000				19,003				178,663				—				—
Eliminations			(3,272,574	)			(1,205,607	)			(664,522	)			(451,599	)			(1,562,199	)			(2,359,256	)			(471,255	)
Retail propane segment			1,162,941				989,628				511,258				449,841				1,284,867				879,556				709,473
Other			14,051				90,516				6,060				43,958				121,278				102,028				75,700
Total revenues			7,499,062				5,403,592				2,349,510				2,162,466				6,792,037				7,859,096				6,168,798
Gross margin			1,761,818				1,412,729				675,856				472,623				1,713,831				1,290,780				787,283
Depreciation and amortization			191,757				145,353				71,333				48,767				179,162				117,415				92,943
Operating income			859,823				721,810				323,634				209,888				829,652				642,871				312,051
Interest expense			191,757				134,101				66,298				54,946				175,563				113,857				93,017
Income from continuing operations before income tax expense and minority interests			723,811				616,057				272,613				164,055				690,939				544,006				209,409
Income tax expense(1)			8,754				10,062				10,789				3,120				13,658				25,920				7,295
Income from continuing operations			715,057				605,107				261,824				160,445				676,139				515,852				201,383
Basic income from continuing operations per limited partner unit(2)			3.06				2.79				1.22				0.70				3.32				3.16				1.51
Diluted income from continuing operations per limited partner unit(2)			3.05				2.79				1.21				0.70				3.31				3.15				1.50
Cash distribution per limited partner unit(3)			2.66				2.42				1.13				*				3.19				2.56				1.89
Balance Sheet Data (at period end):
Current assets			1,681,999				1,041,093				1,409,959				*				1,041,093				1,301,804				1,446,572
Total assets			10,721,308				7,708,428				9,008,161				*				7,708,428				5,455,013				4,415,458
Current liabilities			1,285,636				924,217				1,215,461				*				924,217				1,016,490				1,239,426
Long-term debt, less current maturities			5,509,484				3,626,977				4,297,264				*				3,626,977				2,589,124				1,675,705
Partners’ capital			3,810,107				3,039,833				3,379,191				*				3,039,833				1,736,862				1,326,192
Other Financial Data:
Cash flow provided by operating activities			1,022,585				938,280				245,702				420,910				1,112,732				543,884				169,418
Cash flow used in investing activities			(1,467,412	)			(942,832	)			(995,943	)			(1,344,181	)			(2,158,090	)			(1,244,406	)			(1,133,749	)
Cash flow provided by financing activities			914,434				38,511				738,003				1,019,286				1,088,022				701,649				907,500
Capital expenditures:
Maintenance (accrual basis)			75,931				79,004				48,998				*				89,226				51,826				41,054
Growth (accrual basis)			1,532,458				759,906				604,371				*				998,075				677,861				155,405
Acquisition			62,002				57,856				337,091				*				90,695				586,185				1,131,844

(1)		As a partnership, we are generally not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings, Heritage Service Corporation, and Titan Propane Services, Inc. are corporations subject to income taxes.
(2)		See the notes to our consolidated financial statements included in the quarterly and annual reports incorporated by reference in this prospectus supplement for a discussion of the computation of income per limited partner unit.
(3)		The cash distribution per unit for fiscal year 2006 includes the special SCANA distribution of $0.0325 per unit discussed in Notes 6 and 9 of our consolidated financial statements included in our annual report on Form 10-K for the year ended August 31, 2007 incorporated by reference in this prospectus supplement.
*		As a result of our recent change in fiscal year end, we calculated financial data for the transition period of the four months ended December 31, 2007, but financial data were not calculated for the corresponding period in 2006.

 

An investment in our common units involves risk. You should carefully read the risk factors below and included under the caption “Risk Factors” beginning on page 4 of the accompanying prospectus, together with all of the other information included in, or incorporated by reference into, this prospectus supplement and the accompanying prospectus, when evaluating an investment in our common units.

 

Risks Related to Our Business

 

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

 

Global financial markets and economic conditions 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, we 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, we may be unable to meet our obligations as they come due or we may be required to post collateral to support our obligations. Moreover, without adequate funding, we may be unable to execute our 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 our revenues and results of operations.

 

Completion of pipeline expansion projects will require significant amounts of debt and equity financing which may not be available to us on acceptable terms, or at all.

 

We plan to fund our expansion capital expenditures, including any future pipeline expansion projects we may undertake, with proceeds from sales of our senior notes and common units and borrowings under our revolving credit facility. However, we cannot be certain that we will be able to issue our senior notes and common units on terms satisfactory to us, or at all. In addition, we may be unable to obtain adequate funding under our current revolving credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations. If we are unable to finance our expansion projects as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.

 

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

 

Many of our 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 our 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 bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline system. For example, a number of our customers have announced reduced drilling capital expenditure budgets for 2009. A significant reduction in drilling activity could have a material adverse effect on our operations.

We are exposed to the credit risk of our customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

 

The risks of nonpayment and nonperformance by our customers are a major concern in our 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. We are subject to risks of loss resulting from nonpayment or nonperformance by our 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 our customers. Any substantial increase in the nonpayment and nonperformance by our customers could have a material adverse effect on our results of operations and operating cash flows.

 

The completion of the joint venture with OGE is subject to the timely and successful execution of a financing plan in accordance with specified terms as well as numerous other closing conditions and we may therefore not be able to successfully complete the joint venture.

 

Consummation of the joint venture transaction with OGE is conditioned on receipt of certain third-party consents and certain other customary closing conditions. The transaction is also conditioned upon obtaining financing pursuant to a specified financing plan that would provide ETP Enogex Partners with funds to make payments to us and OGE at the closing of the transaction, to refinance certain existing debt and to provide longer-term credit capacity. Specifically, the financing plan, which we refer to as the ETP Enogex Financing Plan, requires that (a) ETP Enogex Partners enter into at least a $700 million senior secured revolving credit facility having an interest rate of no more than LIBOR plus 275 to 375 basis points (dependent on the facility’s credit ratings), (b) ETP Enogex Partners issue a minimum of $700 million of senior unsecured notes having an interest rate of no more than 9.0% and (c) Transwestern Pipeline Company issue approximately $800 million in senior unsecured notes having an interest rate of no more than 8.0%. We and OGE have agreed that, as a condition to consummation of the transaction, the terms of the ETP Enogex Financing Plan must be at least as favorable to ETP Enogex Partners as certain agreed upon terms, which terms we and OGE believed approximated existing market terms at the time the agreement for this transaction was signed. Subsequent to entering into this agreement, credit markets have deteriorated and we believe that financing for the joint venture is not currently available on terms that would satisfy the financing condition to closing this transaction. Although we and OGE could waive this condition to closing if we mutually agreed to financing terms less favorable than those specified in the contribution agreement, we currently do not intend to waive this condition to closing. As a result, given the recent substantial disruption in the credit markets, we believe it is unlikely that we will be able to obtain financing that meets the minimum specified terms or obtain the consents required to complete the transaction. If the joint venture has not been consummated by March 31, 2009, either we or OGE may terminate the contribution agreement relating to the formation of the joint venture. If the credit markets do not improve significantly prior to March 31, 2009, the ETP Enogex Financing Plan may not be put into place and the agreement to enter into the joint venture may be terminated.

 

The joint venture with OGE, if completed, may not be able to successfully integrate the operations of Enogex and ETP.

 

If the joint venture with OGE is completed, we will, pursuant to a contribution agreement, contribute our 100% equity interest in Transwestern Pipeline Company, our 100% equity interest in ETC Canyon Pipeline and our 50% equity interest in MEP to ETP Enogex Partners, and OGE will contribute its 100% equity interest in Enogex to ETP Enogex Partners, in each case subject to the satisfaction of closing conditions, including ETP Enogex Partners’ obtaining financing in accordance with the ETP Enogex Financing Plan. If ETP Enogex Partners is not able to successfully integrate these operations, it could have an adverse impact on our results of operations.

If the joint venture is completed, we will own 50 percent of the equity in ETP Enogex Partners and will not be able to exercise full control over ETP Enogex Partners.

 

If the joint venture is completed, we will own 50% of the ownership interests in ETP Enogex Partners and ETP Enogex Partners will be managed by a four-person management council, of which we will designate two members and OGE will designate two members. Following an initial period, and assuming the occurrence of certain events, ETP Enogex Partners will be governed by a nine-member board of directors. We will be entitled to designate three members of the board, OGE will be entitled to designate three members of the board and the remaining three members will be mutually agreed upon by us and OGE. Accordingly, we will not be able to exercise full control over ETP Enogex Partners, including with respect to:

 

 

If the joint venture is completed and subsequently unable to obtain adequate financing, we may need to fund our share of ETP Enogex Partners’ capital expenditure requirements.

 

If the joint venture is completed and is not able to obtain adequate financing on favorable terms, we and OGE, as 50% owners of ETP Enogex Partners, may be required to contribute additional funds to support ETP Enogex Partners’ capital expenditure programs.

 

The FERC is pursuing legal action against us relating to certain natural gas trading and transportation activities, and related third party actions have been filed against us and ETE.

 

On July 26, 2007, the FERC issued to us an Order to Show Cause and Notice of Proposed Penalties, which we refer to as the Order and Notice, that contains allegations that we violated FERC rules and regulations. The FERC has alleged that we 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 our commodities derivatives positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods we 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. We allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that we manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. Our Oasis pipeline transports interstate natural gas pursuant to Natural Gas Policy Act, or NGPA, Section 311 authority and is subject to the FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. On October 29, 2008, we moved for summary disposition of the claim that Oasis unduly discriminated against non-affiliated shippers and unduly preferred affiliated shippers. The presiding administrative law judge granted this motion on November 18, 2008, as further discussed below. The FERC also seeks to revoke, for a period of 12 months, our blanket marketing authority for sales of natural gas in interstate commerce at market-based prices, which activity is expected to account for approximately 1.0% of our operating income for our 2008 calendar year. If the FERC is successful in revoking our blanket marketing authority, our sales of natural gas at market-based prices would be limited to sales to retail customers (such as utilities and other end users) and

sales from our own production, and any other sales of natural gas by us would be required to be made at contract prices that would be subject to individual FERC approval.

 

In its Order and Notice, the FERC specified that it was seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC has taken the position that, once it receives our response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial- type hearing before an administrative law judge. On August 27, 2007, ETP filed a request for rehearing of the Order and Notice. On December 20, 2007, the FERC issued an order denying rehearing and directed the FERC Enforcement Staff to file a brief recommending disposition of issues by order or by evidentiary hearing. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. On February 14, 2008, the Enforcement Staff of the FERC filed a brief recommending that the FERC refer various matters relating to its market manipulation allegations for an evidentiary hearing before a FERC administrative law judge. The Enforcement Staff also recommended that the FERC issue an order assessing the $15.5 million portion of the above-referenced penalty against ETP with respect to the allegations related to ETP’s Oasis pipeline and that the Oasis-related penalty assessment, if not paid, then be referred by the FERC to a federal district court for de novo review. The Enforcement Staff also recommended that the FERC impose certain changes in Oasis’s business operations and refunds to certain Oasis customers as previously proposed in the Order and Notice. Finally, the Enforcement Staff 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 FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month. If the FERC pursues the claims related to this additional month, the total amount of civil penalties and disgorgement of profits sought by the FERC would be approximately $200 million. On March 31, 2008, we responded to the Enforcement Staff’s brief. On April 25, 2008, the Enforcement Staff filed an answer to our March 31, 2008 pleading. On May 15, 2008, the FERC ordered hearings to be conducted by FERC administrative law judges with respect to the FERC’s Oasis claims and market manipulation claims. The hearing related to the Oasis claims was scheduled to commence in December 2008 with the administrative law judge’s initial decisions due by May 11, 2009, and the hearing related to the market manipulation claims is scheduled to commence in April 2009 with the administrative law judge’s initial decision due by October 26, 2009. The FERC also ordered that, following the completion of the hearings, the administrative law judges make initial findings with respect to whether we engaged in market manipulation in violation of the NGA and FERC regulations and whether Oasis violated the NGPA and FERC regulations. The FERC reserved for itself the issues of possible civil penalties, the revocation of our blanket market certificate, the method by which we and Oasis would disgorge any unjust profits and whether any conditions should be placed on Oasis’s Section 311 authorization. Following the issuance of each of the administrative law judges’ initial decisions, the FERC would then issue an order with respect to each of these matters. On May 23, 2008, we requested rehearing and stay of the FERC’s May 15, 2008 order establishing hearing, and we renewed those requests on June 26, 2008. On August 7, 2008, FERC denied rehearing of its May 15, 2008 order. On August 8, 2008, we filed a petition with the U.S. Court of Appeals for the Fifth Circuit to review and set aside FERC’s May 15 and August 7, 2008 orders on the grounds that we are entitled to adjudicate FERC’s claims in federal district court pursuant to the NGA and the NGPA. On August 28, 2008, we filed an amended petition seeking review of the Order and Notice and the December 20, 2007 order denying rehearing.

 

On November 18, 2008, the administrative law judge presiding over the Oasis claims granted our motion for summary disposition of the claim that Oasis unduly discriminated in favor of affiliates regarding the provision of Section 311(a)(2) interstate transportation service. We subsequently entered an agreement with the Enforcement Staff to settle all claims related to Oasis. On January 5, 2009, this agreement was submitted under seal to FERC by the presiding administrative law judge, for FERC’s approval as an uncontested settlement of all Oasis claims. If approved by the FERC in its entirety and without modification, the terms of the settlement will become public. If no person seeks rehearing of an order approving the settlement within

30 days of such an order, the FERC’s order would become final and non-appealable. We do not believe the Oasis settlement, as currently agreed upon with the Enforcement Staff, will have a material adverse effect on our business, financial condition or results of operations.

 

It is our position that our trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and we intend to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC holds substantial enforcement authority. At this time, we are unable to predict the final outcome of these matters.

 

On July 26, 2007, the United States Commodity Futures Trading Commission, or the CFTC, filed suit in United States District Court for the Northern District of Texas alleging that we violated provisions of the Commodity Exchange Act, or CEA, by attempting to manipulate natural gas prices in the Houston Ship Channel. On March 17, 2008, we entered into a consent order with the CFTC, which we refer to as the Consent Order. Pursuant to the Consent Order, we agreed to pay the CFTC $10 million and the CFTC agreed to release us and our affiliates, directors and employees from all claims or causes of action asserted by the CFTC in this proceeding. The Consent Order provides that we are permanently enjoined from attempting to manipulate the price of any commodity in interstate commerce in violation of the CEA. By consenting to the entry of the Consent Order, we neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement reduced our existing accrual and was paid from cash flow from operations in March 2008.

 

In addition to the pending FERC legal action, third parties have asserted claims and may assert additional claims against us and ETE for 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 ETE 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 ETE contains an additional allegation that we and ETE 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 also been 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. We have filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable. The claimants agreed to a stay of the arbitration pending resolution of crossmotions for summary judgment in the state court proceeding. On November 12, 2008, the state court granted our motion for summary judgment. The claimants have filed a notice of appeal.

 

A consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action alleges that we 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 CEA. It is further alleged that during the class period of December 29, 2003 to December 31, 2005, we had the market power to manipulate index prices, and that we 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 our natural gas physical and financial trading positions, and that we intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by us 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, we 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, we filed a motion to dismiss the complaint. On June 19, 2008, the plaintiffs filed a response opposing our motion to dismiss. We filed a reply in support of our motion on July 9, 2008.

 

On March 17, 2008, a second class action complaint was filed against us in the United States District Court for the Southern District of Texas. This action alleges that we 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 we exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit our 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, we filed a motion to dismiss this complaint. On July 2, 2008 the plaintiffs filed a response opposing our motion to dismiss. We filed a reply in support of our motion on August 18, 2008.

 

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

 

We will receive net proceeds of approximately $200 million from the sale of 6,000,000 common units we are offering, including our general partner’s proportionate capital contribution and after deducting underwriting discounts and commissions, estimated offering expenses, and giving effect to the reimbursement of expenses by the underwriters.

 

We will use the net proceeds of this offering to repay approximately $200 million outstanding under our revolving credit facility. We expect to use some of the increased availability under the revolving credit facility to finance capital expenditures and other growth projects.

 

As of January 20, 2009, there was a balance of $945 million in revolving credit loans (including a $43 million swingline loan) outstanding and $60 million of letters of credit issued under our revolving credit facility. The weighted average interest rate on the total amount outstanding at January 20, 2009 was 2.08%. Our revolving credit facility matures on July 20, 2012. We use revolving credit loans to fund growth capital expenditures and working capital requirements.

 

We will use any net proceeds from the underwriters’ exercise of their option to purchase additional common units to repay additional borrowings outstanding under our revolving credit facility.

 

Our common units are listed on the NYSE under the symbol “ETP.” The last reported sales price of the common units on the NYSE on January 21, 2009 was $35.11. As of January 5, 2009, we had issued and outstanding 152,102,554 common units, which were held by approximately 118,000 unitholders. The following table sets forth the range of high and low sales prices of the common units, on the NYSE, as well as the amount of cash distributions paid per common unit for the periods indicated.

 

 

 

 

The following table sets forth our consolidated cash and capitalization as of September 30, 2008 on:

 

 

The following table does not give effect to the ETP Enogex Partners joint venture described under the caption “Summary — The Company — Recent Developments — ETP Enogex Partners LLC.” 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, which is incorporated by reference in this prospectus supplement and the accompanying prospectus.

 

 

As of December 31, 2008, we had cash and cash equivalents of approximately $92 million.

 

As of January 20, 2009, there was a balance of $945 million in revolving credit loans (including a $43 million swingline loan) outstanding and $60 million of letters of credit issued under our revolving credit facility.

 

On February 29, 2008, MEP, a company in which we and KMP each own a 50% interest, entered into a credit agreement that provides for a $1.4 billion senior revolving credit facility. We have guaranteed 50% of the obligations of MEP under this facility, with the remaining 50% of MEP’s obligations guaranteed by KMP. As of September 30, 2008, there were $525 million of outstanding borrowings and $33.3 million of letters of credit issued under MEP’s senior revolving credit facility. If our pending transaction with OGE is completed, our guarantee of MEP’s obligations will be reduced to 25% and OGE will guarantee 25% of the obligations of MEP.

 

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. Although this section updates and adds information related to certain tax considerations, it should be read in conjunction with the risk factors included under the caption “Tax Risks to Common Unitholders” beginning on page 25 of the accompanying prospectus and with “Material Income Tax Considerations” in the accompanying prospectus, which provides a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of common units.

 

All prospective unitholders are encouraged to consult with their own tax advisor about the federal, state, local and foreign tax consequences particular to their own circumstances. In particular, ownership of common units by tax-exempt entities, including employee benefit plans and IRAs, and foreign investors raises issues unique to such persons. Such investors should read “Material Income Tax Considerations — Tax-Exempt Organizations and Other Investors” in the accompanying prospectus.

 

Partnership Status

 

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids and certain related hedging activities. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 7% of our current gross income is not qualifying income. However, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. For a discussion related to the opinion of Vinson & Elkins L.L.P. and the importance of our status as a partnership, please read “Material Income Tax Considerations — Partnership Status” in the accompanying prospectus.

 

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Specifically, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Ratio of Taxable Income to Distributions

 

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from our operations will approximate the amount required to make distributions on all our units and other assumptions with respect to our capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

 

Under the terms and subject to the conditions contained in an underwriting agreement dated January 22, 2009, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, UBS Securities LLC and Wachovia Capital Markets, LLC are acting as joint bookrunners and representatives of the underwriters, the following respective number of common units:

 

 

The underwriting agreement provides that the underwriters are obligated to purchase all of the common units if any are purchased, other than those common units covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults on its purchase commitments, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

 

We have granted to the underwriters a 30-day option to purchase an aggregate of not more than 900,000 additional common units at the public offering price less the underwriting discounts and commissions. The underwriters may exercise this option at any time within the 30-day period beginning on the date of this prospectus supplement. The option may be exercised only to cover over-allotments of common units.

 

The underwriters propose to offer the common units initially at the public offering price on the cover page of this prospectus supplement and to selling group members at that price less a selling concession of $0.83 per unit. After the public offering the representatives may change the public offering price and concession and discount to broker/dealers.

 

The following table summarizes the compensation and estimated expenses we will pay:

 

 

We estimate that our portion of the total expenses of this offering will be approximately $500,000. The underwriters have agreed to reimburse us for these expenses.

 

We have agreed that we will not offer, sell, pledge, contract to sell or otherwise dispose of, or grant any option, right or warrant to purchase from us directly or indirectly, enter into any swap, hedge or any other agreement that transfers, in whole or in part, the economic consequences of ownership, establish or increase a “put equivalent position” or liquidate or decrease a “call equivalent position” within the meaning of Section 16 of the Exchange Act, or file with the SEC a registration statement (other than a registration statement relating to our director and employee unit plans) under the Securities Act relating to, any securities substantially similar our common units, or securities convertible into or exchangeable or exercisable for our common units, or publicly disclose our intention to make any offer, sale, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Morgan Stanley & Co.

Incorporated, UBS Securities LLC and Wachovia Capital Markets, LLC for a period of 90 days after the date of this prospectus supplement, subject to certain exceptions, including exceptions that permit us to offer and sell securities pursuant to our director and employee unit plans and awards thereunder, including the forfeiture to us of common units in satisfaction of tax withholding obligations arising in connection with the issuance, vesting or exercise of an award under any such plan, and to issue and sell units to ETE in connection with the financing of the proposed Haynesville Pipeline Project. Please read “Summary — The Company — Recent Developments — Haynesville Pipeline Project.”

 

Our executive officers, our board of directors and our general partner and certain of its affiliates have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any our common units or securities convertible into or exchangeable or exercisable for our common units, enter into a transaction that would have the same effect, offer, sell, contract to sell, contract to purchase any option, right or warrant to purchase our common units or securities convertible into or exchangeable or exercisable for our common units, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common units, or such other securities, whether any such aforementioned transaction is to be settled by delivery of our common units or such other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement or make any demand for or exercise any right with respect to, the registration of our common units or any security convertible into or exercisable or exchangeable for our common units, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, UBS Securities LLC and Wachovia Capital Markets, LLC for a period of 90 days after the date of this prospectus supplement, subject to certain exceptions, including exceptions that permit transfers as bona fide gifts or by will or intestacy by our executive officers and directors in which the transferee agrees to be bound by the restrictions described in the paragraph above.

 

We have agreed to indemnify the underwriters against liabilities, including liabilities under the Securities Act, or to contribute to payments which the underwriters may be required to make in that respect. Our common units are listed on the New York Stock Exchange under the symbol “ETP.”

 

In connection with the offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids.

 

 

 

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of our common units. As a result the price of our common units may be higher than the price that might otherwise exist in the open market. These transactions, if commenced, may be discontinued at any time.

 

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate securities to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters that will make internet distributions on the same basis as other allocations.

 

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”) it has not made and will not make an offer of common units which are the subject of the offering contemplated by this prospectus to the public in that Relevant Member State other than:

 

 

For the purposes of this provision, the expression an “offer of common units to the public” in relation to any common units in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the common units to be offered so as to enable an investor to decide to purchase or subscribe to purchase the common units, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

 

Each underwriter has represented and agreed that:

 

 

Because the Financial Industry Regulatory Authority, or FINRA, views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the Conduct Rules of The National Association of Securities Dealers, Inc. Investor suitability with respect to the

common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of business. In addition, some of the underwriters and their affiliates have engaged in, and may in the future engage in, transactions with us and perform services for us in the ordinary course of their business. In particular, Wachovia Capital Markets, LLC is a joint lead arranger and book runner for our revolving credit facility and is an affiliate of Wachovia Bank, National Association, the administrative agent for our revolving credit facility. In addition, affiliates of Citigroup Global Markets Inc., Wachovia Capital Markets, LLC (including Wachovia Bank, National Association and Wells Fargo Bank, N.A.), Credit Suisse Securities (USA) LLC, UBS Securities LLC, Deutsche Bank Securities Inc., Morgan Stanley & Co. Incorporated and RBC Capital Markets Corporation are lenders and agents under certain of our credit facilities for which they receive interest and fees as provided in the credit agreements related to these facilities. We will use the net proceeds of the offering of the common units to repay outstanding loans and accrued interest under our revolving credit facility. As a result, this offering is subject to the provisions of Rule 5110(h) of FINRA.

 

An affiliate of Credit Suisse Securities (USA) LLC acted as our financial advisor in connection with our pending joint venture with OGE, for which the affiliate was paid a customary financial advisor fee. Citigroup Global Markets Inc., Wachovia Capital Markets, LLC, Credit Suisse Securities (USA) LLC and Lehman Brothers Inc. (now Barclays Capital Inc.) served as joint book-running managers and Morgan Stanley & Co. Incorporated, Deutsche Bank Securities Inc., UBS Securities LLC and RBC Capital Markets Corporation served as co-managers in connection with our July 2008 equity offering, for which they received customary compensation for such services. Additionally, Morgan Stanley & Co. Incorporated, Credit Suisse Securities (USA) LLC and Wachovia Capital Markets, LLC, served as joint book-running managers in connection with our December 2008 senior notes offering, for which they received customary compensation for such services.

 

The validity of the common units offered in this prospectus supplement will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

 

The consolidated financial statements and the effectiveness of internal control over financial reporting of Energy Transfer Partners, L.P. and the consolidated balance sheets of Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.L.C. all incorporated in this prospectus supplement by reference from Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended August 31, 2007 and the consolidated financial statements of Energy Transfer Partners, L.P. and the consolidated balance sheets of Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.L.C. all incorporated in this prospectus supplement by reference from Energy Transfer Partners, L.P.’s Current Report on Form 8-K filed on March 19, 2008 have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said reports.

 

We file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s web site at http://www.sec.gov. We also make available free of charge on our website, at http://www.energytransfer.com, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Additionally, you can obtain information about us through the New York Stock Exchange, 20 Broad Street, New York, New York 10005, on which our common units are listed.

 

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus supplement by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and results of operations. The information incorporated by reference is an important part of this prospectus supplement and the accompanying prospectus. Information that we file later with the SEC will automatically update and may replace information in this prospectus supplement and information previously filed with the SEC.

 

We incorporate by reference in this prospectus supplement the documents listed below:

 

 

 

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 http://www.energytransfer.com, or by writing or calling us at the address set forth below. Information on our website is not incorporated into this prospectus supplement, the accompanying prospectus or our other securities filings and is not a part of this prospectus supplement or the accompanying prospectus.

 

Energy Transfer Partners, L.P.
3738 Oak Lawn Avenue
Dallas, TX 75219
Attention: Thomas P. Mason
Telephone: (214) 981-0700

Prospectus

 

 

ENERGY TRANSFER PARTNERS, L.P.

 

 

Common Units

Debt Securities

 

 

We may offer and sell the common units, representing limited partner interests of Energy Transfer Partners, L.P., and debt securities described in this prospectus from time to time in one or more classes or series and in amounts, at prices and on terms to be determined by market conditions at the time of our offerings.

 

We may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis. This prospectus describes the general terms of these common units and debt securities and the general manner in which we will offer the common units and debt securities. The specific terms of any common units and debt securities we offer will be included in a supplement to this prospectus. The prospectus supplement will also describe the specific manner in which we will offer the common units and debt securities.

 

Investing in our common units and debt securities involves risks. Limited partnerships are inherently different from corporations. You should carefully consider the risk factors described under “Risk Factors” beginning on page 4 of this prospectus before you make an investment in our securities.

 

Our common units are traded on the New York Stock Exchange, or the NYSE, under the symbol “ETP.” We will provide information in the prospectus supplement for the trading market, if any, for any debt securities we may offer.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is December 11, 2007.

 

TABLE OF CONTENTS

 

 

 

In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with any other information. If anyone provides you with different or inconsistent information, you should not rely on it.

 

You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. You should not assume that the information contained in the documents incorporated by reference in this prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

 

This prospectus is part of a registration statement that we have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf registration process, we may, over time, offer and sell any combination of the securities described in this prospectus in one or more offerings. This prospectus generally describes Energy Transfer Partners, L.P. and the securities. Each time we sell securities with this prospectus, we will provide you with a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add to, update or change information in this prospectus. Before you invest in our securities, you should carefully read this prospectus and any prospectus supplement and the additional information described under the heading “Where You Can Find More Information.” To the extent information in this prospectus is inconsistent with information contained in a prospectus supplement, you should rely on the information in the prospectus supplement. You should read both this prospectus and any prospectus supplement, together with additional information described under the heading “Where You Can Find More Information,” and any additional information you may need to make your investment decision. All references in this prospectus to “we,” “us,” “ETP,” the “Partnership” and “our” refer to Energy Transfer Partners, L.P.

 

We are a publicly traded limited partnership that owns and operates a diversified portfolio of energy assets. Our natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas treating and processing assets located in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, and three natural gas storage facilities located in Texas. These assets include approximately 14,000 miles of intrastate pipeline in service, with an additional 500 miles of intrastate pipeline under construction, and 2,400 miles of interstate pipelines. We are also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

Our principal executive offices are located at 3738 Oak Lawn Avenue, Dallas, Texas 75219, and our telephone number at that location is (214) 981-0700.

 

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

 

 

 

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

 

An investment in our securities involves a high degree of risk. You should carefully consider the following risk factors, together with all of the other information included in, or incorporated by reference into, this report in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units or debt securities could decline and you could lose all or part of your investment. When we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement.

 

Risks Inherent In An Investment In Us

 

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

 

The amount of cash we can distribute on our common units or other partnership securities depends upon the amount of cash we generate from our operations. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:

 

 

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

 

 

 

Because of all these factors, we cannot guarantee that we will have sufficient available cash to pay a specific level of cash distributions to our unitholders.

 

Furthermore, you should be aware that the amount of cash we have available for distribution depends primarily upon our 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, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.

 

We may sell additional limited partner interests, diluting existing interests of unitholders.

 

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

 

 

Future sales of our units or other limited partner interests in the trading market could reduce the market price of unitholders’ limited partner interests.

 

As of August 31, 2007, Energy Transfer Equity, L.P., or ETE, and its affiliates owned 62,500,797 common units. ETE owns our general partner. If ETE were to sell and/or distribute its common units to the holders of its equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the public markets could reduce the market price of our outstanding common units.

 

Our increased debt level and debt agreements may limit our ability to make distributions to unitholders and our future financial and operating flexibility.

 

As of August 31, 2007, we had approximately $3.7 billion of consolidated debt outstanding. Our level of indebtedness affects our operations in several ways, including, among other things:

 

 

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

 

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of August 31, 2007, we had approximately $3.7 billion of consolidated debt, of which approximately $2.7 billion was at fixed interest rates and approximately $1.0 billion was at variable interest rates. We have entered interest rate swaps for a total notional amount of $125.0 million, resulting in a net amount of $875.01 million of variable-rate debt at August 31, 2007. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements. To the extent that we have debt with variable interest rates that is not hedged, our results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates.

 

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

 

The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

 

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

 

Entities controlling the owner of our general partner have significant indebtedness outstanding and are dependent principally on the cash distributions from their general and limited partner equity interests in us to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us, ETP GP and ETP LLC from the entities that control ETP GP, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of such entities were viewed as substantially lower or more risky than ours.

 

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

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. We are managed by our general partner, Energy Transfer Partners GP, L.P., or ETP GP, which in turn is managed by its general partner, Energy Transfer Partners, L.L.C., or ETP LLC. Our unitholders did not elect our general partner and will have no right to elect our general partner on an annual or other continuing basis. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors of our general partner, ETP GP, and its general partner, ETP LLC, have a fiduciary duty to manage the general partner and its general partner in a manner beneficial to the owners of those entities.

 

Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 662/3% of the outstanding units voting together as a single class, including units owned by the general partner and its affiliates. As of August 31, 2007, ETE and its affiliates held approximately 46% of our outstanding units, with an approximately 1% of units held by our officers and directors. Consequently, it could be difficult to remove the general partner without the consent of the general partner and our affiliates.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner and its affiliates, cannot be voted on any matter.

 

The control of our general partner may be transferred to a third party without unitholder consent.

 

The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the general partner of our general partner from transferring its general partner interest in our general partner to a third party. Any new owner of the general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions taken by such officers.

 

Unitholders may be required to sell their units to the general partner at an undesirable time or price.

 

If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.

 

The interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make distributions to our partners.

 

We are a holding company with no business operations. Our only significant assets are the equity interests we own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity investees and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our partners.

 

Cost reimbursements due our general partner may be substantial and reduce our ability to pay the distributions to unitholders.

 

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

 

Unitholders may have liability to repay distributions.

 

Under certain circumstances unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

Risks Related to Conflicts of Interest

 

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty

 

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates and which reduce the obligations to which our general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partner to the limited partners. Our partnership agreement:

 

 

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

 

Some of our executive officers and directors face potential conflicts of interest in managing our business.

 

Certain of our executive officers and directors are also officers and/or directors of ETE. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among us and ETE. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

 

The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

 

Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

 

Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of unitholders.

 

As of August 31, 2007, ETE and its affiliates directly and indirectly owned an aggregate limited partner interest in us of approximately 46% and our officers and directors owned approximately 1% of the limited partner interests in us. Conflicts of interest could arise in the future as a result of relationships between 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 those of its affiliates over the interests of the unitholders. The nature of these conflicts includes the following considerations:

 

 

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

 

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

 

Risks Related to our Business

 

The profitability of our midstream and intrastate transportation and storage operations are largely 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 our control and have been volatile.

 

Income from our midstream and intrastate transportation and storage operations are exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the North Texas System, Southeast Texas System and at our Houston Pipe Line System, or the HPL System, we purchase natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gather and deliver the natural gas to pipelines where we typically resell the natural gas at the index price or gas daily average. Generally, the gross margins we realize under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

 

For a portion of the natural gas gathered and processed at the North Texas System and Southeast Texas System, we enter into percentage-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit

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, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements our 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 our results of operations. Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we 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, our revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if we are not able to bypass our processing plants and sell the unprocessed natural gas. Under processing fee agreements, we process the gas for a fee. If recoveries are less than those guaranteed the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole with regard to contractual recoveries.

 

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during our fiscal year ended August 31, 2007, the NYMEX settlement price for the prompt month contract ranged from a high of $8.87 per MMBtu to a low of $4.20 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during our fiscal year ended August 31, 2007 ranged from a high of approximately $1.15 per gallon to a low of approximately $0.83 per gallon. Natural gas prices are subject to significant fluctuations, and we cannot assure you that natural gas prices will remain at the high levels recently experienced.

 

Our Oasis pipeline, East Texas pipeline, ET Fuel System and HPL System receive fees for transporting natural gas for our 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 our transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels. Our fuel retention fees are also directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees, and decreases in natural gas prices tend to decrease our fuel retention fees.

 

The markets and prices for natural gas and NGLs depend upon factors beyond our 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 us.

 

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

 

Our success depends upon our ability to continually contract for new sources of natural gas supply.

 

In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our 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 our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. The primary factors affecting our ability to attract customers to our transportation pipelines consist of our 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. We have no control over the level of drilling activity in our 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, we have 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 our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. Accordingly, our cash flows will also decline unless we are able to access new supplies of natural gas by connecting additional production to these systems.

 

Our transportation pipelines are also dependent upon natural gas production in areas served by our pipelines or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. A material decrease in natural gas production in our areas of operation or in other areas that are connected to our 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 we handle, which would reduce our revenues and operating income. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

 

Transwestern derives a significant portion of its revenue from charges to its customers for reservation of capacity, which charges Transwestern receives regardless of whether these customers actually use the reserved capacity. Transwestern also generates revenue from transportation of natural gas for customers without reserved capacity. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in demand for natural gas transportation on the

Transwestern system in the long run. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.

 

The volumes of natural gas we transport on our 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 our 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 we operate.

 

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for qualified assets.

 

Our 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 our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.

 

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

 

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact the market price of our securities.

 

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

 

At August 31, 2007, our consolidated balance sheet reflected $718.4 million of goodwill and $211.7 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

 

If we do not make acquisitions on economically acceptable terms, our future growth could be limited.

 

Our results of operations and our ability to grow and to increase distributions to unitholders have depended principally on our ability to make acquisitions that are accretive to our distributable cash flow per unit.

 

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

 

 

 

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

 

 

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

 

If we do not continue to construct new pipelines, our future growth could be limited.

 

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

 

 

Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results from those projected prior to commencement of construction and other factors.

 

Expanding our business by constructing new pipelines and treating and processing facilities subjects us to risks.

 

One of the ways that we have grown our business is through the construction of additions to our 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 our control and require the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately following the completion of particular projects. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our revenues until long after the project’s completion. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return, which could adversely affect our results of operations and financial condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.

 

We depend on certain key producers for our 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 our financial results.

 

For our fiscal year ended August 31, 2007, ConocoPhillips Company, Enervest Operating, L.L.C., Encana Oil and Gas (USA) Inc., and Lear Energy, LP supplied us with approximately 90% of the Southeast Texas System’s natural gas supply. For our fiscal year ended August 31, 2007, Encana Oil and Gas (USA), Inc., EOG Resources, Inc., XTO Energy Inc., and Chesapeake Energy Marketing, Inc. supplied us with approximately 80% of the North Texas System’s natural gas supply. We are 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 us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.

 

We depend on key customers to transport natural gas on our East Texas pipeline, ET Fuel System and HPL System.

 

We have nine- and ten-year fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on our pipelines. We also have an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which we refer to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. We have also entered into two eight-year natural gas storage contracts with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on our cash flow and results of operations if we were not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

 

We completed our Cleburne to Carthage pipeline in April 2007. The major shippers through the Cleburne to Carthage pipeline expansion to interstate and intrastate markets are XTO Energy, Inc., EOG Resources, Inc., Chesapeake Energy Marketing, Inc., Encana Marketing (USA), Inc., Quicksilver Resources, Inc., and Leor Energy, L.P. These shippers have long-term contracts ranging from five to 10 years. The failure of these shippers to fulfill their contractual obligations could have a material adverse effect on our cash flow and results of operations if we 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 our business.

 

Transwestern is subject to regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or NGA. Our midstream intrastate transportation and storage operations are generally exempt from such regulation, but FERC regulation still significantly affects our business and the market for our

products. The rates, terms and conditions of some of the transportation and storage services we provide on the HPL System, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than our currently approved rates, we may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, or 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.

 

Our pipelines and storage facilities are subject to state regulation in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, the states in which we operate these types of pipelines. Our intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge 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, our business may be adversely affected.

 

Our gathering operations are subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract 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 we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate 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 our business.

 

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

 

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

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

 

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

 

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

 

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

 

It is our position that our trading and transportation activities during the periods at issue complied in all material respects with applicable laws and regulations, and we intend to contest these cases, and any third party actions, vigorously. However, the laws and regulations related to alleged market manipulation are vague,

subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, neither we nor ETE is able to predict the final outcome of these matters.

 

In addition to the FERC and CFTC legal actions, third parties have asserted claims and may assert additional claims against us and ETE for damages related to these matters. In this regard, two natural gas producers have initiated legal proceedings against us and ETE for claims related to the FERC and CFTC claims. One of the producers has brought two separate suits in Texas state court, one of which names us and ETE and the other of which names two of our subsidiaries as the only defendants. Both suits are based on contractual and tort claims relating to alleged manipulation of natural gas prices at the Waha Hub in West Texas and the Houston Ship Channel and seek unspecified direct, indirect, consequential and exemplary damages. The suit against us and ETE contains an additional allegation that the defendants transported gas in a manner that favored their affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. The second producer, acting as agent for a group of producers, has brought suit in Texas state court against us and ETE based on contract and tort claims relating to a natural gas purchase contract to which we and this producer are parties. This producer seeks unspecified damages and requests pre-arbitration discovery of information related to our activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. This producer also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5.9 million, plus interest and costs. This producer has also filed a complaint at FERC against us and ETE requesting an agency hearing and claiming that we and ETE violated the NGA by failing to make sales for resale at negotiated rates; intentionally engaged in market manipulation; knowingly submitted misleading information to Platts; and caused damages to the producer group in the amount of $5.9 million. This producer has requested refunds and other remedies. In addition to these producer lawsuits, a natural gas marketing company has brought suit against us and ETE in Texas state court seeking a declaratory judgment that we manipulated the Houston Ship Channel, the Waha Hub and El Paso Permian natural gas price indices during an unspecified time period. The marketer seeks unspecified monetary damages from us and ETE, including direct, indirect and consequential damages for tort claims related to this alleged manipulation. The marketer also seeks judgment against us for exemplary damages on this basis.

 

In addition, a consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action alleges that we 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. It is further alleged that during the class period December 29, 2003 to December 31, 2005, we had the market power to manipulate index prices, and that we used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, Waha, and Permian hubs, in order to benefit our natural gas physical and financial trading positions and intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we also violated the CEA because we knowingly aided and abetted violations of the CEA. This action alleges that this unlawful depression of index prices by us manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to plaintiff and all other members of the putative class who purchased and/or sold natural gas futures and options contracts on NYMEX during the class period. The class action complaint consolidated two class actions which were pending against us. Following the consolidation order, the plaintiffs who had filed these two earlier class actions filed the consolidated complaint. They have requested certification of their suit as a class action, unspecified damages, court costs and other appropriate relief.

 

We are expensing the legal fees, consultants’ fees and related expenses relating to the FERC and CFTC legal actions, and third party actions in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obligated to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as

developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obligated to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

 

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

 

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

 

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

 

The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates of an interstate petroleum products pipeline, Santa Fe Pacific Pipeline, or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification to those rates. The Court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, the FERC issued its first case-specific oil pipeline review of the income tax allowance issues in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income allowance. Further, in the December 2005 order, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through

entities pay the maximum marginal tax rate of 35% and that noncorporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the new income tax allowance policy were appealed to the D.C. Circuit. In May 2007, the D.C. Circuit affirmed FERC’s favorable income tax allowance policy. As a result, we remain eligible to include an allowance in the tariff rates we charge for natural gas transportation on our Transwestern interstate pipeline system, subject to our ability to demonstrate compliance with FERC’s policy. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. As FERC has recently approved our tariff rates specified in a settlement agreement with shippers, the allowance for income taxes as a cost-of-service element in our tariff rates is not subject to challenge by parties to our settlement agreement prior to its expiration.

 

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

 

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

 

 

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

 

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

 

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

 

Our business involves hazardous substances and may be adversely affected by environmental regulation.

 

Our natural gas as well as our 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 our operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from our pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from our operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

We may incur substantial environmental costs and liabilities because the underlying risk are inherent to our operations. Joint and several, strict liability may be incurred under environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons or wastes on, under, or from our properties and facilities, many of which have been used for industrial activities for a number of years. Private parties, including the owners of properties through which our gathering systems pass or facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. At August 31, 2007, the total accrued future estimated cost of remediation activities relating to our Transwestern pipeline operations is approximately $12.3 million, which activities are expected to continue for several years.

 

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

 

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

 

Users of our 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 our 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 our pipelines. Any reduction in volumes transported in our pipelines would adversely affect our revenues and cash flow.

 

We encounter competition from other midstream, transportation and storage companies and propane companies.

 

We experience competition in all of our markets. Our 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 our transportation pipeline systems. Our 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 we compete with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P., and Enbridge, Inc. Some of our competitors may have greater financial resources and access to larger natural gas supplies than we do.

 

The acquisitions of the HPL System and the Transwestern pipeline increased the number of interstate pipelines and natural gas markets to which we have access and expanded our principal areas of competition to areas such as southeast Texas and the Texas Gulf Coast. As a result of our expanded market presence and diversification, we face 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 we do.

 

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

 

Our 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 our retail outlets. As a result, we are always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of our propane retail branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:

 

 

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

 

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

We are exposed to the credit risk of our customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

 

The risks of nonpayment and nonperformance by our customers are a major concern in our 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. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any substantial increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

 

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

 

Because of our ownership of the Oasis pipeline and ET Fuel System, we can generally elect to bypass the processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the Oasis pipeline and ET Fuel System. In some circumstances, such as when we do not have a sufficient amount of lean gas to blend with the volume of rich gas that we receive at the processing plant, we may have to process the rich gas. If we have to process when processing margins are unfavorable, our results of operations will be adversely affected.

 

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

 

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

 

For our fiscal year ended August 31, 2007, approximately 22.4% of our 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 us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

 

Our storage business depends on neighboring pipelines to transport natural gas.

 

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

 

Our pipeline integrity program may cause us to incur significant costs and liabilities.

 

Our operations are subject to regulation by the U.S. Department of Transportation, or DOT, under the Pipeline Hazardous Materials Safety Administration, or PHMSA, pursuant to which the PHMSA has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as

“high consequence areas.” Based on the results of our current pipeline integrity testing programs, we estimate that compliance with these federal regulations and analogous state pipeline integrity requirements for our existing transportation assets other than the Transwestern pipeline will result in capital costs of $7.9 million during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $13.1 million during that period. During this same time period, we estimate that we will incur pipeline integrity operating and on-going annual maintenance capital costs of $18.7 million with respect to our Transwestern Pipeline. Through August 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through August 31, 2007, a total of $13.4 million of capital costs and $11.8 million of operating and maintenance costs have been incurred for pipeline integrity testing for transportation assets other than Transwestern. Through August 31, 2007, a total of $2.9 million of capital costs and $0.1 million of operating and maintenance costs have been incurred for pipeline integrity testing for Transwestern. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

 

Since weather conditions may adversely affect demand for propane, our 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 our customers rely heavily on propane as a heating fuel. Typically, we sell approximately two-thirds of our retail propane volume during the peak-heating season of October through March. Our 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 our operating and financial results, our access to capital and our acquisition activities may be limited. Variations in weather in one or more of the regions where we operate can significantly affect the total volume of propane that we sell and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including periods of unseasonably cold or hot periods or dry weather conditions which may impact agricultural operations.

 

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow and, accordingly, affect the market price of our common units.

 

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

 

If one or more facilities that are owned by us or that deliver natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our 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 our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, adversely affect the market price of our common units.

 

We believe that we maintain adequate insurance coverage, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on

our 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 our facilities could adversely affect our 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 our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.

 

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our 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, our 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, we may be unable to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or other market conditions over which we have no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve their propane usage or convert to alternative energy sources.

 

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

 

We generally attempt to minimize our cost and inventory risk related to our 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, we may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in our facilities, at major storage facilities owned by third parties or for future delivery. This strategy may not be effective in limiting our 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 we made such purchases, it could adversely affect our profits.

 

Some of our propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to our anticipated sales volumes under the commitments, we 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. We enter into such contracts and exercise such options at volume levels that we believe are necessary to manage these commitments. The risk management of our inventory and contracts for the future purchase of product could impair our profitability if the customers do not fulfill their obligations.

 

We also engage 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 our 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 our control occur, such activities could generate a loss in future periods and potentially impair our profitability.

We are dependent on our principal propane suppliers, which increases the risk of an interruption in supply.

 

During fiscal 2007, we purchased approximately 23% and 22% of our propane from Targa Liquids and Enterprise Products Operating L.P., respectively. In addition, we purchased approximately 21% of our propane from M-P Energy Partnership, a Canadian partnership in which we owned through August 31, 2007 a 60% interest. Enterprise is a subsidiary of Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding common units and a 34.9% non-controlling interest in the General Partner of ETE, and is therefore considered to be an affiliate of us. Titan purchases substantially all of its propane from Enterprise pursuant to an agreement that expires in 2010. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

 

Historically, a substantial portion of the propane that we purchase has originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to us 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 we use, would adversely affect our ability to obtain propane.

 

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

 

Competition in our 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 us to lose customers, thereby reducing our 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 our operations.

 

Energy efficiency and technological advances may affect the demand for propane and adversely affect our 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 our operations.

 

Tax Risks to Common Unitholders

 

In addition to reading the following risk factors, you should read “Material Income Tax Considerations” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

 

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

 

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

 

Despite the fact that we are a limited partnership under Delaware law, Section 7704 of the Internal Revenue Code provides that publicly traded partnerships such as ours may be treated as a corporation for

federal income tax purposes unless 90% or more of the gross income for every taxable year consists of “qualifying income.” As a result of our tax termination on May 7, 2007, we will have two tax years in 2007, and each of our tax years must independently meet the qualifying income exception. For our tax year beginning January 1, 2007 and ending May 7, 2007, we estimate that less than 5% of our gross income was not qualifying income. For our tax year beginning May 8, 2007 and ending December 31, 2007, we estimate that less than 9% of our gross income for that period will not be qualifying income. Our estimate of income that is not qualifying income is higher in the tax period beginning May 8, 2007 and ending December 31, 2007 due to one or more non-reoccurring income items that we have earned or will earn during such period. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. For a discussion related to the opinion of Vinson & Elkins L.L.P. and the importance of our status as a partnership, please read “Material Income Tax Considerations — Partnership Status.”

 

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

 

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, beginning in 2008, we will be required to pay Texas franchise tax at a minimum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. If any state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Specifically, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.

 

The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the

market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our unitholders.

 

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

 

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income. In such case, unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.

 

Tax gain or loss on disposition of our common units could be more or less than expected.

 

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Income Tax Considerations — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

 

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

 

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

 

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

 

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

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

 

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

 

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

 

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

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Income Tax Considerations — Disposition of Common Units — Allocations Between Transferors and Transferees.”

 

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our public unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our General Partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating

the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of our unitholders.

 

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

 

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

 

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

 

Based on the information currently available to us, we believe that we exceeded the 50% threshold on May 7, 2007, and, as a result, we have determined that our partnership has terminated and immediately reconstituted as a new partnership for federal tax income purposes on that date. This tax termination does not affect our classification as a partnership for federal income tax purposes or otherwise affect the nature of our “qualifying income” for federal income tax purposes. However, this tax termination will require us to close our taxable year, and as a result, we will have two tax years in 2007, and each of our tax years must independently meet the qualifying income exception. Moreover, the closing of our taxable year will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and will require us to make new elections as to various tax matters and reset the depreciation schedule for our depreciable assets for federal income tax purposes. The resetting of our depreciation schedule will result in a deferral of the depreciation deductions allowable in computing the taxable income allocated to our unitholders. However, certain elections we will make in connection with this tax termination will allow us to utilize deductions for the amortization of certain intangible assets for purposes of computing the taxable income allocable to certain of our unitholders, which deductions had not previously been utilized in computing taxable income allocable to our unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our income or loss being includable in their taxable income for the year of termination.

 

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

 

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

 

Except as otherwise provided in the applicable prospectus supplement, we will use the net proceeds we receive from the sale of the securities for general partnership purposes, which may include repayment of indebtedness, the acquisition of businesses and other capital expenditures and additions to working capital.

 

Any specific allocation of the net proceeds of an offering of securities to a specific purpose will be determined at the time of the offering and will be described in a prospectus supplement.

 

On January 20, 2004, we completed a series of transactions whereby, among other things, (1) Energy Transfer Equity, L.P. (formerly La Grange Energy, L.P., or La Grange Energy), contributed La Grange Acquisition, L.P., or ETC OLP, to us, (2) Energy Transfer Equity, L.P. obtained control of us by acquiring all of the interests in our general partner and the general partner of our general partner, (3) our general partner contributed its general partner interest in Heritage Operating, L.P., or HOLP, to us, and (4) we purchased the outstanding capital stock of Heritage Holdings, Inc. We refer to these transactions collectively as the Energy Transfer Transactions. Although Heritage Propane Partners, L.P. was the surviving parent entity for legal purposes in the Energy Transfer Transactions, ETC OLP was the acquirer for accounting purposes. As a result, following the Energy Transfer Transactions, the historical financial statements of ETC OLP for periods prior to the closing of the Energy Transfer Transactions became our historical financial statements. ETC OLP was formed on October 1, 2002 and has an August 31 year-end. ETC OLP’s predecessor entities had a December 31 year-end. Accordingly, ETC OLP’s 11-month period ended August 31, 2003 is treated as a transition period.

 

The ratio of earnings to fixed charges for the period from October 1, 2002 to August 31, 2003 has been derived from the historical financial statements of ETC OLP, which are not included or incorporated by reference in this prospectus supplement. During this time period, ETC OLP owned the Southeast Texas System and the Elk City System. From October 1, 2002 through December 27, 2002, ETC OLP also owned a 50% equity interest in Oasis Pipe Line Company, which owns the Oasis pipeline. After December 27, 2002, ETC OLP owned a 100% interest in Oasis Pipe Line.

 

The following table sets forth our historical consolidated ratio of earnings to fixed charges for the periods indicated therein:

 

 

For these ratios “earnings” is the amount resulting from adding the following items:

 

 

The term “fixed charges” means the sum of the following:

 

 

As of September 1, 2007, there were approximately 77,443 individual common unitholders, which includes common units held in street name. Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified our Amended and Restated Agreement of Limited Partnership, as amended to date.

 

Common Units

 

As of August 31, 2007, we had 136,981,221 common units outstanding, of which 73,383,908 were held by the public, 62,500,797 were held by ETE, and 1,095,208 were held by our officers and directors. As of such date, the common units represent an aggregate 98.0% limited partner interest in us. Our general partner owns an aggregate 2.0% general partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended and are listed for trading on the NYSE. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

 

Class E Units

 

In conjunction with our purchase of the capital stock of Heritage Holdings in January 2004, the 4,426,916 common units held by Heritage Holdings were converted into 4,426,916 Class E Units. Pursuant to our two-for-one unit split completed on March 15, 2005, there are currently 8,853,832 Class E Units outstanding, all of which are owned by Heritage Holdings. The Class E Units generally do not have any voting rights. These Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all unitholders, including the Class E unitholders, up to $1.41 per unit per year. Management plans to continue its ownership of the Class E Units by Heritage Holdings indefinitely.

 

Issuance of Additional Securities

 

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion, without the approval of the unitholders. Any such additional partnership securities may be senior to the common units.

 

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

 

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, in the sole discretion of the general partner, have special voting rights to which the common units are not entitled.

 

Upon issuance of additional partnership securities, our general partner will be required to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than the general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Unitholder Approval

 

The following matters require the approval of the majority of the outstanding common units, including the common units owned by the general partner and its affiliates:

 

 

The removal of our general partner requires the approval of not less than 662/3% of all outstanding units, including units held by our general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by our general partner and its affiliates.

 

Amendments to Our Partnership Agreement

 

Amendments to our partnership agreement may be proposed only by our general partner. Certain amendments require the approval of a majority of the outstanding common units, including common units owned by the general partner and its affiliates. Any amendment that materially and adversely affects the rights or preferences of any class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the class of partnership interests so affected. Our general partner may make amendments to the partnership agreement without unitholder approval to reflect:

 

 

 

Withdrawal or Removal of Our General Partner

 

Our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

 

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.

 

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist, our general partner will have the right to receive cash in exchange for its partnership interest as a general partner in us, its partnership interest as the general partner of any member of the Energy Transfer partnership group and its incentive distribution rights. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of the majority of our outstanding common units, including those held by our general partner and its affiliates.

 

While our partnership agreement limits the ability of our general partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our general partner. In addition, our partnership agreement expressly permits the sale, in whole or in part, of the ownership of our general partner. Our general partner may also transfer, in whole or in part, any common units it owns.

 

Liquidation and Distribution of Proceeds

 

Upon our dissolution, unless we are reconstituted and continue as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

 

 

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.

 

Limited Call Right

 

If at any time less than 20% of the outstanding common units of any class are held by persons other than our general partner and its affiliates, our general partner will have the right to acquire all, but not less than all, of those common units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. Our general partner may assign this purchase right to any of its affiliates or us.

 

Indemnification

 

Under our partnership agreement, in most circumstances, we will indemnify our general partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

 

Listing

 

Our outstanding common units are listed on the NYSE under the symbol “ETP.” Any additional common units we issue also will be listed on the NYSE.

 

Transfer Agent and Registrar

 

The transfer agent and registrar for the common units is American Stock Transfer & Trust Company.

 

Transfer of Common Units

 

Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units:

 

 

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Although the general partner has no current intention of doing so, it may withhold its consent in its sole discretion. An assignee who is not admitted as a limited partner will remain an assignee. An assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Furthermore, our general partner will vote and exercise other powers attributable to common units owned by an assignee at the written direction of the assignee.

 

Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:

 

 

Thus, a purchaser of common units who does not execute and deliver a transfer application:

 

 

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or NYSE regulations.

 

Status as Limited Partner or Assignee

 

Except as described under “— Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.

 

Limited Liability

 

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:

 

 

Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.

 

Our subsidiaries currently conduct business in 41 states: Alabama, Alaska, Arizona, California, Colorado, Delaware, Florida, Georgia, Idaho, Illinois, Indiana, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michigan, Missouri, Minnesota, Mississippi, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South Carolina, South Dakota, Tennessee, Texas, Utah, Vermont, Virginia, Washington, West Virginia and Wyoming. To maintain the limited liability for Energy Transfer Partners, L.P., as the holder of a 100% limited partner interest in Heritage Operating, L.P., we may be required to comply with legal requirements in the jurisdictions in which Heritage Operating, L.P. conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our limited partner interest in Heritage Operating, L.P. or otherwise, conducting business in any state without compliance with the applicable limited partnership statute, or that our right or the exercise of our right to remove or replace Heritage Operating, L.P.’s general partner, to approve some amendments to Heritage Operating, L.P.’s partnership agreement, or to take other action under Heritage Operating, L.P.’s partnership agreement constituted “participation in the control” of Heritage Operating, L.P.’s business for purposes of the statutes of any relevant jurisdiction, then we could be held personally liable for Heritage Operating, L.P.’s obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner as our general partner considers reasonable and necessary or appropriate to preserve our limited liability.

 

Meetings; Voting

 

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

 

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by

proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

 

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. However, if at any time any person or group, other than our general partner and its affiliates, owns, in the aggregate, beneficial ownership of 20% or more of the common units then outstanding, the person or group will lose voting rights on all of its common units and its common units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

 

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

 

Books and Reports

 

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. Reporting for tax purposes is done on a calendar year basis.

 

We will furnish or make available to record holders of common units, within 75 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days after the close of each quarter.

 

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

 

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

 

 

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

 

Distributions of Available Cash

 

General.  We will distribute all of our “available cash” to our unitholders and our general partner within 45 days following the end of each fiscal quarter. Definition of Available Cash. Available Cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:

 

 

 

 

Operating Surplus and Capital Surplus

 

General.  All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We distribute available cash from operating surplus differently than available cash from capital surplus.

 

Definition of Operating Surplus.  Operating surplus for any period generally means:

 

 

Definition of Capital Surplus.  Generally, capital surplus will be generated only by:

 

 

Characterization of Cash Distributions.  We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating

surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $10.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that enables us, if we choose, to distribute as operating surplus up to $10.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We have not made, and we anticipate that we will not make, any distributions from capital surplus.

 

Incentive Distribution Rights

 

Incentive distribution rights represent the contractual right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution as been paid. Please read “— Distributions of Available Cash from Operating Surplus” below. The general partner owns all of the incentive distribution rights, except that in conjunction with the August 2000 transaction with U.S. Propane, L.P., we issued 1,000,000 class C units to Heritage Holdings, Inc., our general partner at that time, in conversion of that portion of Heritage Holdings, Inc.’s incentive distribution rights that entitled it to receive any distribution made by us of funds attributable to the net amount received by us in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation. In January 2004, the class C units were distributed by Heritage Holdings, Inc. to the owners of its equity interests. On July 14, 2006, all 1,000,000 outstanding class C units were retired and cancelled.

 

Distributions of Available Cash from Operating Surplus

 

We are required to make distributions of available cash from operating surplus for any quarter in the following manner:

 

 

Notwithstanding the foregoing, the distributions on each class E unit may not exceed $1.41 per year.

 

On November 7, 2007, our general partner approved an amendment to the Amended and Restated Agreement of Limited Partnership of ETP, and this amendment became effective on November 9, 2007. This amendment changes the fiscal year of ETP from a year ending on August 31 to a year ending on December 31. In order to transition to the new fiscal year, the amendment also provides that, in lieu of making a cash distribution to ETP’s unitholders, general partner and holder of the incentive distribution rights with respect to the three-month period ending November 30, 2007, ETP will make a cash distribution for the four-month period ending December 31, 2007, which distribution will be made within 45 days following the end of such four-month period. The amendment also specifies proportional adjustments to the cash distribution target levels

relating to the incentive distribution rights for this four-month period in order to reflect the longer period upon which the distribution will be made (essentially multiplying each cash distribution target level by 4/3). Finally, the amendment provides that, following this one-time four-month distribution period, ETP will make cash distributions with respect to each calendar quarter within 45 days following the end of each calendar quarter.

 

Distributions of Available Cash from Capital Surplus

 

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

 

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price per common unit less any distributions of capital surplus per unit is referred to as the “unrecovered capital”.

 

If we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust our minimum quarterly distribution; our target cash distribution levels; and our unrecovered capital.

 

For example, if a two-for-one split of our common units should occur, our unrecovered capital would each be reduced to 50% of our initial level. We will not make any adjustment by reason of our issuance of additional units for cash or property.

 

On January 14, 2005, our general partner announced a two-for-one split of our common units that was effected on March 15, 2005. As a result, our minimum quarterly distribution and the target cash distribution levels were reduced to 50% of their initial levels. Our adjusted minimum quarterly distribution and the adjusted target cash distribution levels are reflected in the discussion above under the caption “Distributions of Available Cash from Operating Surplus.”

 

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce our minimum quarterly distribution and the target cash distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates.

 

Distributions of Cash Upon Liquidation

 

General.  If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

 

Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

 

Manner of Adjustments for Gain.  The manner of the adjustment for gain is set forth in our partnership agreement in the following manner:

 

 

 

 

 

 

 

 

 

 

 

Manner of Adjustments for Losses.  Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner:

 

 

Adjustments to Capital Accounts upon the Issuance of Additional Units.  We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 

Energy Transfer Partners, L.P. may issue senior debt securities on a senior unsecured basis under an indenture among Energy Transfer Partners, L.P., as issuer, the Subsidiary Guarantors, if any, and a trustee that we will name in the related prospectus supplement. We refer to this senior indenture as the indenture. The debt securities will be governed by the provisions of the indenture and those made part of the indenture by reference to the Trust Indenture Act.

 

We have summarized material provisions of the indenture and the debt securities below. This summary is not complete. We have filed the indenture with the SEC as an exhibit to the registration statement, and you should read the indenture for provisions that may be important to you.

 

References in this “Description of the Debt Securities” to “we,” “us” and “our” mean Energy Transfer Partners, L.P.

 

Provisions Applicable to the Indenture

 

General.  Any series of debt securities will be general obligations of the issuer.

 

The indenture does not limit the amount of debt securities that may be issued under the indenture, and does not limit the amount of other unsecured debt or securities that we may issue. We may issue debt securities under the indenture from time to time in one or more series, each in an amount authorized prior to issuance.

 

The indenture does not contain any covenants or other provisions designed to protect holders of the debt securities in the event we participate in a highly leveraged transaction or upon a change of control. The indenture also does not contain provisions that give holders the right to require us to repurchase their securities in the event of a decline in our credit ratings for any reason, including as a result of a takeover, recapitalization or similar restructuring or otherwise.

 

Terms.  We will prepare a prospectus supplement and either a supplemental indenture, or authorizing resolutions of the board of directors of our general partner’s general partner, accompanied by an officers’ certificate, relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:

 

 

 

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

 

We may sell the debt securities at a discount, which may be substantial, below their stated principal amount. These debt securities may bear no interest or interest at a rate that at the time of issuance is below market rates. If we sell these debt securities, we will describe in the prospectus supplement any material United States federal income tax consequences and other special considerations.

 

If we sell any of the debt securities for any foreign currency or currency unit or if payments on the debt securities are payable in any foreign currency or currency unit, we will describe in the prospectus supplement the restrictions, elections, tax consequences, specific terms and other information relating to those debt securities and the foreign currency or currency unit.

 

The Subsidiary Guarantees.  Certain of our subsidiaries, which we refer to collectively as Subsidiary Guarantors, may fully, irrevocably and unconditionally guarantee on an unsecured basis all series of our debt securities and will execute a notation of guarantee as further evidence of their guarantee. The applicable prospectus supplement will describe the terms of any guarantee by the Subsidiary Guarantors.

 

If a series of debt securities is so guaranteed, the Subsidiary Guarantors’ guarantee of the debt securities will be the Subsidiary Guarantors’ unsecured and unsubordinated general obligation, and will rank on a parity with all of the Subsidiary Guarantors’ other unsecured and unsubordinated indebtedness. The obligations of each Subsidiary Guarantor under its guarantee of the debt securities will be limited to the maximum amount that will not result in the obligations of the Subsidiary Guarantor under the guarantee constituting a fraudulent conveyance or fraudulent transfer under federal or state law, after giving effect to:

 

 

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to debt securities of a particular series as described below in “— Defeasance,” then any Subsidiary Guarantor will be released with respect to that series. Further, if no default has occurred and is continuing under the indenture, and to the extent not otherwise prohibited by the indenture, a Subsidiary Guarantor will be unconditionally released and discharged from the guarantee:

 

 

Events of Default.  Unless we inform you otherwise in the applicable prospectus supplement, the following are events of default with respect to a series of debt securities:

 

 

 

 

A default under one series of debt securities will not necessarily be a default under another series. The trustee may withhold notice to the holders of the debt securities of any default or event of default (except in any payment on the debt securities) if the trustee considers it in the interest of the holders of the debt securities to do so.

 

If an event of default for any series of debt securities occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the outstanding debt securities of the series affected by the default (or, in the case of the fourth bullet point appearing above under the heading “— Events of Default”, at least 25% in principal amount of all debt securities issued under the indenture that are affected, voting as one class) may declare the principal of and all accrued and unpaid interest on those debt securities to be due and payable. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, the principal of and interest on all the debt securities issued under the indenture will become immediately due and payable without any action on the part of the trustee or any holder. The holders of a majority in principal amount of the outstanding debt securities of the series affected by the default may in some cases rescind this accelerated payment requirement (other than acceleration for nonpayment of principal of or premium or interest on or any additional amounts with respect to the debt securities).

 

A holder of a debt security of any series issued under the indenture may pursue any remedy under the indenture only if:

 

 

This provision does not, however, affect the right of a holder of a debt security to sue for enforcement of any overdue payment.

In most cases, holders of a majority in principal amount of the outstanding debt securities of a series (or of all debt securities issued under the indenture that are affected, voting as one class) may direct the time, method and place of:

 

 

Under the indenture we are required to file each year with the trustee a written statement as to our compliance with the covenants contained in the indenture.

 

Modification and Waiver.  The indenture may be amended or supplemented if the holders of a majority in principal amount of the outstanding debt securities of all series issued under the indenture that are affected by the amendment or supplement (acting as one class) consent to it. Without the consent of the holder of each debt security affected, however, no modification may:

 

 

The indenture may be amended or supplemented or any provision of the indenture may be waived without the consent of any holders of debt securities issued under the indenture:

 

 

 

The holders of a majority in principal amount of the outstanding debt securities of any series (or, in some cases, of all debt securities issued under the indenture that are affected, voting as one class) may waive any existing or past default or event of default with respect to those debt securities. Those holders may not, however, waive any default or event of default in any payment on any debt security or compliance with a provision that cannot be amended or supplemented without the consent of each holder affected.

 

Defeasance.  When we use the term defeasance, we mean discharge from some or all of our obligations under the indenture. If any combination of funds or government securities are deposited with the trustee under the indenture sufficient to make payments on the debt securities of a series issued under the indenture on the dates those payments are due and payable, then, at our option, either of the following will occur:

 

 

If a series of debt securities is defeased, the holders of the debt securities of the series affected will not be entitled to the benefits of the indenture, except for obligations to register the transfer or exchange of debt securities, replace stolen, lost or mutilated debt securities or maintain paying agencies and hold moneys for payment in trust. In the case of covenant defeasance, our obligation to pay principal, premium and interest on the debt securities and, if applicable, guarantees of the payments will also survive.

 

Unless we inform you otherwise in the prospectus supplement, we will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the debt securities to recognize income, gain or loss for U.S. federal income tax purposes. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the U.S. Internal Revenue Service or a change in law to that effect.

 

No Personal Liability of General Partner.  Our general partner, and its directors, officers, employees, incorporators and partners, in such capacity, will not be liable for the obligations of Energy Transfer Partners, L.P. or any Subsidiary Guarantor under the debt securities, the indenture or the guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. By accepting a debt security, each holder of that debt security will have agreed to this provision and waived and released any such liability on the part of our general partner and its directors, officers, employees, incorporators and partners. This waiver and release are part of the consideration for our issuance of the debt securities. It is the view of the SEC that a waiver of liabilities under the federal securities laws is against public policy and unenforceable.

 

Governing Law.  New York law will govern the indenture and the debt securities.

 

Trustee.  We may appoint a separate trustee for any series of debt securities. We use the term “trustee” to refer to the trustee appointed with respect to any such series of debt securities. We may maintain banking and other commercial relationships with the trustee and its affiliates in the ordinary course of business, and the trustee may own debt securities.

 

Form, Exchange, Registration and Transfer.  The debt securities will be issued in registered form, without interest coupons. There will be no service charge for any registration of transfer or exchange of the debt securities. However, payment of any transfer tax or similar governmental charge payable for that registration may be required.

 

Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the indenture. Holders may present debt securities for registration of transfer at the office of the security registrar or any transfer agent we designate. The security registrar or transfer agent will effect the transfer or exchange if its requirements and the requirements of the indenture are met.

The trustee will be appointed as security registrar for the debt securities. If a prospectus supplement refers to any transfer agents we initially designate, we may at any time rescind that designation or approve a change in the location through which any transfer agent acts. We are required to maintain an office or agency for transfers and exchanges in each place of payment. We may at any time designate additional transfer agents for any series of debt securities.

 

In the case of any redemption, we will not be required to register the transfer or exchange of:

 

 

Payment and Paying Agents.  Unless we inform you otherwise in a prospectus supplement, payments on the debt securities will be made in U.S. dollars at the office of the trustee and any paying agent. At our option, however, payments may be made by wire transfer for global debt securities or by check mailed to the address of the person entitled to the payment as it appears in the security register. Unless we inform you otherwise in a prospectus supplement, interest payments may be made to the person in whose name the debt security is registered at the close of business on the record date for the interest payment.

 

Unless we inform you otherwise in a prospectus supplement, the trustee under the indenture will be designated as the paying agent for payments on debt securities issued under the indenture. We may at any time designate additional paying agents or rescind the designation of any paying agent or approve a change in the office through which any paying agent acts.

 

If the principal of or any premium or interest on debt securities of a series is payable on a day that is not a business day, the payment will be made on the following business day. For these purposes, unless we inform you otherwise in a prospectus supplement, a “business day” is any day that is not a Saturday, a Sunday or a day on which banking institutions in New York, New York or a place of payment on the debt securities of that series is authorized or obligated by law, regulation or executive order to remain closed.

 

Subject to the requirements of any applicable abandoned property laws, the trustee and paying agent will pay to us upon written request any money held by them for payments on the debt securities that remains unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment. In that case, all liability of the trustee or paying agent with respect to that money will cease.

 

Book-Entry Debt Securities.  The debt securities of a series may be issued in the form of one or more global debt securities that would be deposited with a depositary or its nominee identified in the prospectus supplement. Global debt securities may be issued in either temporary or permanent form. We will describe in the prospectus supplement the terms of any depositary arrangement and the rights and limitations of owners of beneficial interests in any global debt security.

 

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy Transfer Partners, L.P. and our operating company.

 

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

 

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

 

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

 

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

 

Partnership Status

 

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

 

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year

consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof, including the retail and wholesale marketing of propane, certain hedging activities and the transportation of propane and natural gas liquids. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. As a result of our tax termination on May 7, 2007, we will have two tax years in 2007, and each of our tax years must independently meet the qualifying income exception. For our tax year beginning January 1, 2007 and ending May 7, 2007, we estimate that less than 5% of our gross income was not qualifying income. For our tax year beginning May 8, 2007 and ending December 31, 2007, we estimate that less than 9% of our gross income for that period will not be qualifying income. Our estimate of income that is not qualifying income is higher in the tax period beginning May 8, 2007 and ending December 31, 2007 due to one or more non-reoccurring income items that we have earned or will earn during such period. For the calendar year 2008, we anticipate that the percentage of our gross income that will not be qualifying income will decrease; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

 

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

 

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

 

(a) Except for Oasis Pipeline Company, we nor our operating entities have elected or will elect to be treated as a corporation;

 

(b) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

 

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

 

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts) we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

 

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be

treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

 

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

 

Limited Partner Status

 

Unitholders who have become limited partners of Energy Transfer Partners, L.P. will be treated as partners of Energy Transfer Partners, L.P. for federal income tax purposes. Also:

 

(a) assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

 

(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

 

will be treated as partners of Energy Transfer Partners, L.P. for federal income tax purposes. As there is no direct or indirect controlling authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

 

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

 

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Energy Transfer Partners, L.P.

 

Tax Consequences of Unit Ownership

 

Flow-Through of Taxable Income.  We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

 

Treatment of Distributions.  Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end

of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

 

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

 

Basis of Common Units.  A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

 

Limitations on Deductibility of Losses.  The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder estate, trust, or a corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these allowances must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

 

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

 

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive

losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

 

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

 

Limitations on Interest Deductions.  The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

 

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

 

Entity-Level Collections.  If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

 

Allocation of Income, Gain, Loss and Deduction.  In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

 

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in an offering will be essentially the same as if the tax bases of our assets were equal to their fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all holders of partnership interests immediately prior to such other transactions, including purchasers of common units in this offering, to account

for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

 

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

 

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

 

Treatment of Short Sales.  A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

 

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

 

Alternative Minimum Tax.  Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

 

Tax Rates.  In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual

where the asset disposed of was held for more than twelve months at the time of disposition is scheduled to remain at 15.0% for years 2008 through 2010 and then increase to 20.0% beginning January 1, 2011.

 

Section 754 Election.  We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

 

Where the remedial allocation method is adopted (which we have historically adopted as to all property other than certain goodwill properties and which we will generally adopt as to all properties going forward), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. If we elect a method other than the remedial method with respect to a goodwill property, Treasury Regulation Section 1.197-2(g)(3) generally requires that the Section 743(b) adjustment attributable to an amortizable Section 197 intangible, which includes goodwill properties, should be treated as a newly-acquired asset placed in service in the month when the purchaser acquires the common unit. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. If we elect a method other than the remedial method with respect to a goodwill property, the common basis of such property is not amortizable. Please read “— Uniformity of Units.”

 

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulation Section 1.197-2(g)(3). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

 

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

 

Tax Treatment of Operations

 

Accounting Method and Taxable Year.  We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

 

Initial Tax Basis, Depreciation and Amortization.  The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interest in us prior to such offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

 

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Because our general partner may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill properties conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

 

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely

be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

 

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

 

Valuation and Tax Basis of Our Properties.  The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

 

Disposition of Common Units

 

Recognition of Gain or Loss.  Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

 

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

 

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as long term capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15% through December 31, 2010. However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

 

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding

period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

 

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

 

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

 

Allocations Between Transferors and Transferees.  In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

 

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

 

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

 

Notification Requirements.  A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination.  We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

 

Uniformity of Units

 

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

 

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulation Section 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

 

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

 

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

 

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

 

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

 

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

 

Administrative Matters

 

Information Returns and Audit Procedures.  We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

 

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

 

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

 

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

Nominee Reporting.  Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

(b) whether the beneficial owner is:

 

1. a person that is not a United States person;

 

2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

3. a tax-exempt entity;

 

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

 

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

 

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

Accuracy-Related Penalties.  An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

 

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

(1) for which there is, or was, “substantial authority”; or

 

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.

 

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.

 

Reportable Transactions.  If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

 

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

 

 

We do not expect to engage in any “reportable transactions.”

 

State, Local, Foreign and Other Tax Considerations

 

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will currently own property or conduct business in more than 40 states. Most of these states impose an income tax on individuals, corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.