Preliminary Prospectus

The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell these securities and they are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

We are offering $ aggregate principal amount of our % Senior Notes due 2023, or 2023 notes, and $ aggregate principal amount of our % Senior Notes due 2043, or 2043 notes. We refer to the 2023 notes and 2043 notes, collectively, as the notes.

Interest on the notes will accrue from , 2013 and will be payable semiannually on and of each year, beginning on , 2013. The 2023 notes will mature on , 2023 and the 2043 notes will mature on , 2043.

We may redeem some or all of the notes of each series at our option at any time and from time to time prior to their maturity at the applicable redemption prices set forth in this prospectus supplement, plus accrued and unpaid interest. Please read the section entitled “Description of Notes—Optional Redemption.”

The notes are our unsecured senior obligations. If we default, your right to payment under the notes will rank equally with the right to payment of the holders of our other current and future unsecured senior debt, including our existing senior notes and the existing senior notes and debentures of Sunoco, Inc., of which we are a co-obligor, and senior in right of payment to all of our future subordinated debt. The notes will not initially be guaranteed by our subsidiaries.

The notes are new issues of securities with no established trading markets. We do not intend to apply for the listing of the notes on any securities exchange or for the quotation of the notes on any automated dealer quotation system.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of 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.

Investing in the notes involves risks. Please read “Risk Factors” beginning on page S-12 of this prospectus supplement and page 4 of the accompanying prospectus and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the notes.

¹ Plus accrued interest from January , 2013, if settlement occurs after that date.

The underwriters expect to deliver the notes in book-entry form only through The Depository Trust Company on or about January , 2013.

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

Generally, when we refer to this “prospectus,” we are referring to both documents combined. If the description of this offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

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

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 the notes by you under applicable laws. You should consult with your own advisors as to the legal, tax, business, financial and related aspects of an investment in the notes.

PROSPECTUS SUPPLEMENT SUMMARY

This summary highlights information included or incorporated by reference in this prospectus supplement. It does not contain all of the information that you should consider before making an investment decision. You should read carefully the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer herein for a more complete understanding of this offering.

Unless the context otherwise requires, references to (1) “Energy Transfer,” “ETP,” “we,” “us,” “our” and similar terms, as well as references to the “Partnership,” are to Energy Transfer Partners, L.P. and all of its subsidiaries, and (2) “ETE” are to Energy Transfer Equity, L.P., the owner of our general partner. With respect to the cover page and in the sections entitled “Prospectus Supplement Summary—The Offering,” “Description of Notes” and “Underwriting,” “we,” “our” and “us” refer only to Energy Transfer Partners, L.P. and not to any of its subsidiaries.

Energy Transfer Partners, L.P.

Overview

We are a publicly traded limited partnership that owns and operates, through our subsidiaries and joint ventures, a diversified portfolio of energy assets, including interstate and intrastate natural gas, natural gas liquids, refined products and crude oil pipelines; natural gas storage, treating and conditioning facilities; natural gas processing plants and retail gasoline stations. We operate our business in six primary segments:

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intrastate transportation and storage;

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interstate transportation;

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midstream;

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natural gas liquids, or NGL, transportation and services;

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investment in Sunoco Logistics Partners L.P., or Sunoco Logistics; and

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retail marketing and wholesale distribution.

Our other operations include natural gas distribution and our ownership of interests in certain businesses engaged in compression services, retail propane distribution and refining. In October 2012, we completed our merger with Sunoco, Inc., or Sunoco, and certain related transactions, which resulted in (i) us acquiring the general partner interests, all of the incentive distribution rights and a 32.4% limited partner interest in Sunoco Logistics, (ii) us owning a 40% economic interest in ETP Holdco Corporation, or ETP Holdco, and controlling 60% of the voting interest in ETP Holdco and (iii) ETP Holdco owning 100% of Southern Union Company, or Southern Union, and Sunoco. Please read “—Recent Developments—Sunoco Merger and Related Transactions.”

Our Business

Natural Gas and NGL Operations

Intrastate Transportation and Storage

We own and operate approximately 7,800 miles of intrastate natural gas transportation pipelines, which is the largest intrastate pipeline system in the United States, and three natural gas storage facilities in Texas. Our intrastate pipeline system has an aggregate throughput capacity of approximately 14.1 billion cubic feet per day, or Bcf/d, of natural gas and interconnects to many major consumption areas in the United States. For the year ended December 31, 2011, we transported an average of 11.3 Bcf/d of natural gas through our intrastate natural gas pipeline system.

We also provide natural gas storage services for third parties for which we charge storage fees as well as injection and withdrawal fees from the use of our three natural gas storage facilities. Our storage facilities have an aggregate working gas throughput capacity of approximately 74 billion cubic feet. In addition to our natural gas storage services, we utilize our Bammel gas storage facility to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. These transactions typically involve a purchase of physical natural gas that is injected into our storage facilities and a related sale of natural gas pursuant to financial futures contracts at a price sufficient to cover our natural gas purchase price and related carrying costs and provide for a gross profit margin.

Interstate Transportation

Our interstate transportation segment includes the following interstate pipeline systems:

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Transwestern Pipeline. The Transwestern pipeline is a 2,690-mile open-access natural gas interstate pipeline extending from the gas producing regions of west Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of the system and to pipeline interconnects off the west end of the system at the California border. The Transwestern pipeline has a throughput capacity of 2.1 Bcf/d of natural gas and access to three significant gas basins: the Permian Basin in west Texas and eastern New Mexico, the San Juan Basin in northwest New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandle.

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Tiger Pipeline. The Tiger pipeline is a 195-mile, 42-inch interstate natural gas pipeline that connects to our dual 42-inch pipeline system near Carthage, Texas, and extends through the heart of the Haynesville Shale ending near Delhi, Louisiana. The Tiger pipeline has interconnects to at least seven interstate pipelines at various points in Louisiana. The Tiger pipeline was placed in service in December 2010 with an initial capacity of 2.0 Bcf/d, and expanded in August 2011, bringing its total capacity to 2.4 Bcf/d.

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Panhandle Eastern Pipe Line, Trunkline and Sea Robin Transmission Systems. The transmission systems of our subsidiaries, Panhandle Eastern Pipe Line Company, LP, Trunkline Gas Company, LLC and Sea Robin Pipeline Company, LLC, comprise a large natural gas open-access interstate pipeline network that serves the midwest, Gulf Coast and midcontinent regions of the United States. This pipeline network consists of six large diameter pipelines extending approximately 2,700 miles; two offshore Louisiana natural gas supply systems extending approximately 81 miles into the Gulf of Mexico; five natural gas storage fields in Illinois, Kansas, Louisiana, Michigan and Oklahoma; and one LNG terminal in Lake Charles, Louisiana.

In addition to the above interstate pipeline systems, we have an interest in the following regulated interstate pipeline systems through our interest in various unconsolidated joint ventures:

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Florida Gas Transmission Company. We and Kinder Morgan, Inc. each own a 50% interest in Citrus Corp., or Citrus, an entity that owns Florida Gas Transmission Company LLC, or FGT. FGT owns and operates an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,300 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The pipeline system has access to numerous offshore and onshore natural gas producing basins via pipeline interconnects with over 66 interstate and intrastate natural gas pipelines. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 63% of the natural gas consumed in the state for the year ended December 31, 2011. In addition, as of December 31, 2011, FGT’s pipeline system had over 290 delivery points in total, with over 250 delivery points in Florida.

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Fayetteville Express Pipeline. We and Kinder Morgan Energy Partners, L.P. each own a 50% interest in Fayetteville Express Pipeline, LLC, or FEP, a joint venture that owns the 185-mile

Fayetteville Express pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express pipeline has a throughput capacity of 2.0 Bcf/d.

Midstream

We own and operate approximately 12,200 miles of natural gas gathering pipelines, nine natural gas processing plants, 20 natural gas treating facilities and three natural gas conditioning facilities. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas, and our operations are currently concentrated in major producing basins, including the Barnett Shale and Woodford Shale in north Texas, the Bossier Sands in east Texas, the Austin Chalk trend and Eagle Ford Shale in south Texas, the Permian Basin in west Texas and New Mexico and the Haynesville Shale in north Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.

In February 2011, we announced that we had entered into multiple long-term agreements with shippers to provide additional transportation services from the Eagle Ford Shale. We completed the initial phase of the Rich Eagle Ford Mainline pipeline, or REM pipeline, in October 2011. The initial phase consisted of 160 miles of 30-inch pipeline and had an initial capacity of 400 million cubic feet per day, or MMcf/d. This rich gas gathering system originates in Dimmitt County, Texas and extends to our Chisholm pipeline for ultimate deliveries to our existing processing plants and to a new 120 MMcf/d processing plant, which we completed in the first quarter of 2012. In April 2011 and February 2012, we announced that we had entered into additional long-term fee-based agreements with multiple producers to provide natural gas gathering, processing and liquids services from the Eagle Ford Shale. To facilitate these agreements, we expanded the REM pipeline in the third quarter of 2012 to increase the capacity to 1.0 Bcf/d and constructed a new 200 MMcf/d processing facility in Karnes County, Texas, which was placed in service in December 2012. We have also announced construction of another processing plant in Jackson County, Texas, with initial capacity of 400 MMcf/d, which is expected to be in service in the first quarter of 2013.

NGL Transportation and Services

In May 2011, we and Regency Energy Partners LP, or Regency, formed a joint venture, Lone Star NGL LLC, or Lone Star, owned 70% by us and 30% by Regency, to acquire all of the membership interests in LDH Energy Asset Holdings LLC for $1.98 billion in cash. Lone Star owns and operates a diverse set of midstream energy assets that represent critical infrastructure connecting high-growth production areas to end-markets. The Lone Star assets include NGL and refined products storage facilities located in Mont Belvieu, Texas and Hattiesburg, Mississippi; a 12-inch long-haul intrastate NGL pipeline, which we refer to as the West Texas pipeline, originating in the Permian Basin in west Texas, passing through the Barnett Shale production area and terminating at Mont Belvieu; NGL fractionation and natural gas processing facilities near Baton Rouge and New Orleans, Louisiana; and a 20% equity interest in the Sea Robin wet gas processing plant near Henry Hub, Louisiana. The Mont Belvieu storage facility has approximately 43 million barrels, or MMBbls, of storage capacity in 24 underground salt dome caverns. The Hattiesburg facility has three salt dome caverns, with 9.6 MMBbls of total cavern capacity, and two brine ponds with combined capacity of over 75 thousand barrels, or MBbls. The intrastate pipeline assets include the approximately 1,300 mile West Texas pipeline with approximately 140 MBbls per day, or MBbls/d, of capacity, 12 pump stations providing 21,500 horsepower of compression, and over 20 injection points. The NGL fractionation and processing facilities consist of one fractionation unit with 25 MBbls/d of capacity, two cryogenic processing plants with combined capacity of 82 MMcf/d. The Sea Robin wet gas processing plant has 850 MMcf/d of natural gas capacity and 26 MBbls/d of NGL capacity.

Since its formation, Lone Star has commenced or recently completed the following construction projects:

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Mont Belvieu Fractionation Facilities. In December 2012, Lone Star completed construction of a 100 MBbls/d NGL fractionation facility at Mont Belvieu. The facility handles NGL barrels from Regency, as well as from our processing facility in Jackson County, Texas, which is supported by multiple 10-year contracts with producers as part of our Eagle Ford Shale projects. Lone Star is also constructing a second 100 MBbls/d NGL fractionation facility at Mont Belvieu, which is supported by multiple long-term contracts and is expected to be completed in the fourth quarter of 2013. As part of the construction at Mont Belvieu, Lone Star will develop additional storage facilities for NGLs and other liquids and include interconnectivity infrastructure to provide NGL suppliers with significant access to storage, other fractionators, pipelines and multiple markets along the Texas and Louisiana Gulf Coast.

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West Texas Gateway NGL Pipeline. In the fourth quarter of 2012, Lone Star completed construction of the West Texas Gateway NGL pipeline, a 570-mile, 16- inch intrastate NGL pipeline that extends from Winkler County in west Texas to our Jackson County, Texas processing facility. This new pipeline has an initial capacity of approximately 209 MBbls/d with the potential to increase pipeline capacity. The project currently has approximately 65% of the capacity subscribed with key producers and processors under 15-year agreements. In addition, Lone Star has secured capacity on its 130-mile Justice NGL pipeline, which extends from Jackson County to Mont Belvieu.

In addition to our Lone Star operations, we also own 100% of and operate, four NGL pipelines in east Texas, with total capacity of 170 MBbls/d.

Investment in Sunoco Logistics

In connection with the completion of the Sunoco merger and certain related transactions in October 2012, we acquired the general partner interests, all of the incentive distribution rights and a 32.4% limited partner interest in Sunoco Logistics. Sunoco Logistics, through its wholly owned subsidiary, Sunoco Logistics Partners Operations L.P., or Sunoco Operations, owns and operates a logistics business, consisting of complementary pipeline, terminalling and acquisition and marketing assets, used in the purchase, sale, transportation and storage of crude oil, refined petroleum products and NGLs. Sunoco Logistics’ portfolio of geographically diverse assets earns revenues in 29 states located throughout the United States, and its business is comprised of four segments:

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The Crude Oil Pipelines segment consists of approximately 5,400 miles of crude oil pipelines, located principally in Oklahoma and Texas.

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The Crude Oil Acquisition and Marketing business gathers, purchases, markets and sells crude oil using Sunoco Logistics’ fleet of approximately 200 crude oil transport trucks and third-party assets and approximately 120 crude oil truck unloading facilities.

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The Terminal Facilities consist of an aggregate crude oil and refined petroleum products storage capacity of approximately 40 MMBbls, including the 22 MMBbls Nederland, Texas crude oil terminal; the five MMBbls Eagle Point, New Jersey refined products and crude oil terminal; approximately 40 active refined petroleum products marketing terminals located in the northeast, midwest and southwest United States; and several refinery terminals located in the northeast United States.

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The Refined Products Pipeline System consists of approximately 2,500 miles of refined product pipelines and joint venture interests in four refined products pipelines.

Retail Marketing and Wholesale Distribution

Our retail marketing and wholesale distribution business, which we conduct through Sunoco, consists of the retail sale of gasoline and middle distillates and the operation of convenience stores in 23 states,

primarily on the east coast and in the midwest region of the United States. Our highest concentrations of outlets are located in Connecticut, Florida, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Virginia. Some of these outlets are traditional locations that sell fuel products under the Sunoco^® and Coastal^® brands whereas others are APlus^® convenience stores or Ultra Service Centers^® that provide automotive diagnostics and repair. Our branded fuels sales (including middle distillates) averaged 326.8 thousand barrels per day in 2011. The Sunoco^® brand is positioned as a premium brand, and is the official fuel of NASCAR^® and the INDYCAR^® series through 2019 and 2014, respectively. Additionally, our APlus^® convenience stores are the official convenience stores of NASCAR^®.

Other Operations

Our other operations consist of (i) our ownership of all the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas; (ii) the local distribution of natural gas in Missouri and Massachusetts through our 40% indirect ownership in Southern Union; (iii) a 33% non-operating minority interest in a joint venture that owns a refinery in Philadelphia, Pennsylvania, which we own through our 40% indirect ownership of Sunoco, and (iv) our 31.9% limited partner interest in AmeriGas, which engages in retail propane operations. In December 2012, Southern Union entered into definitive purchase and sale agreements to dispose of its natural gas distribution business. Please read “—Recent Developments—Southern Union Local Distribution Company Dispositions.”

Business Strategy

Our business strategy is to increase unitholder distributions and the value of our common units. We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through internally generated expansion and measures aimed at increasing the profitability of our existing assets. We intend to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each common unit.

We believe that we are well-positioned to compete in the natural gas, NGL and crude oil industries based on the following strengths:

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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.

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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 ETE, the entity that indirectly owns our general partner, and therefore benefits from incentive distribution payments we make to our general partner.

We intend to accomplish our business strategy by executing on the following operating strategies:

Enhancing profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes of natural gas and NGLs under long-term producer commitments, increasing refined product and crude oil pipeline and terminal throughput, undertaking additional initiatives to enhance utilization, reducing costs by improving operations and realizing operational and commercial synergies by focusing on the integration of our recently acquired assets.

Engaging in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding our natural gas, NGL and crude

oil systems to meet new or increased demand for midstream and transportation services. Further, we intend to continue expansion capital projects on our existing refined products and crude oil assets to, among other things, expand services at our refined products terminals and increase tankage at our terminalling facilities.

Increasing cash flow from fee-based businesses. We intend to seek to increase the percentage of our midstream business conducted with third parties under fee-based arrangements in order to reduce our exposure to changes in the prices of natural gas and NGLs.

Recent Developments

Sunoco Merger

On October 5, 2012, our wholly owned subsidiary, Sam Acquisition Corporation, completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 54,971,724 of our common units and a total of approximately $2.6 billion in cash. We used approximately $2.0 billion of Sunoco’s cash on hand to partially fund the cash portion of the merger consideration, and funded the remaining cash portion of the merger consideration, approximately $620 million, with borrowings under our revolving credit facility.

Pursuant to the terms of the Sunoco merger agreement, immediately prior to the effective time of the merger, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to us, in exchange for 90,706,000 newly issued Class F units representing limited partner interests in us. The Class F units are entitled to 35% of the quarterly cash distribution generated by us and our subsidiaries other than ETP Holdco, subject to a maximum cash distribution of $3.75 per Class F unit per year. Based on the current level of our quarterly cash distribution, the Class F units are entitled to the maximum $3.75 per Class F unit per year.

Immediately following the closing of the Sunoco merger, ETE contributed to ETP Holdco its 100% equity interest in Southern Union, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, we contributed our 100% equity interest in Sunoco (exclusive of our interests in Sunoco Logistics) to ETP Holdco, and we retained a 40% equity interest in ETP Holdco. We refer to this transaction as the Holdco restructuring. Pursuant to a stockholders agreement between ETE and us, we control ETP Holdco. In accordance with the transaction agreement governing the Holdco restructuring, ETE agreed to relinquish an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco restructuring. The relinquishment applied to the distribution we paid on November 14, 2012 with respect to the third quarter ended September 30, 2012.

Southern Union Local Distribution Company Dispositions

On December 17, 2012, Southern Union entered into definitive purchase and sale agreements with subsidiaries of the Laclede Group, Inc., or Laclede, to sell the assets of its Missouri Gas Energy and New England Gas Company divisions. The aggregate value of the transactions are approximately $1.035 billion, subject to customary closing adjustments, comprised of $1.015 billion in cash and approximately $20 million of assumed debt of the New England Gas Company division. The transactions are expected to close before the end of the third quarter of 2013, subject to customary closing conditions, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and applicable regulatory approvals from the Missouri Public Service Commission and the Massachusetts Department of Public Utilities. We intend to use the net proceeds from these transactions to repay a portion of the outstanding indebtedness of Southern Union, in order to maintain investment grade credit metrics. We refer to these transactions as the Southern Union local distribution company dispositions.

The Offering

We provide the following summary solely for your convenience. This summary is not a complete description of the notes. You should read the full text of, and more specific details contained elsewhere in, this prospectus supplement and the accompanying prospectus. For a more detailed description of the notes, please read the section entitled “Description of Notes” in this prospectus supplement and the section entitled “Description of the Debt Securities” in the accompanying prospectus.

Issuer

Energy Transfer Partners, L.P.

Notes Offered

We are offering $ aggregate principal amount of notes of the following series:

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$ % Senior Notes due 2023; and

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$ % Senior Notes due 2043.

Maturity

Unless redeemed prior to maturity as described below, the 2023 notes will mature on , 2023 and the 2043 notes will mature on , 2043.

Interest Rate

Interest on the 2023 notes will accrue at the per annum rate of % and interest on the 2043 notes will accrue at the per annum rate of %.

Interest Payment Dates

Interest on the notes will accrue from, and including, the issue date of the notes and be payable semiannually on and of each year, beginning on , 2013.

Ranking

The notes will be our unsecured senior obligations. The notes will rank equally with all of our other current and future unsecured senior debt, including our existing senior notes and Sunoco’s existing senior notes and debentures of which we are a co-obligor, and junior to the indebtedness and other obligations, including trade payables, of our subsidiaries.

As of September 30, 2012, after giving effect to (i) the consummation of the Sunoco merger and Holdco restructuring, (ii) the Southern Union local distribution company dispositions and the use of the cash consideration therefrom as described in “Capitalization” and (iii) the public offering by Sunoco Logistics of $700 million in aggregate principal amount of senior notes and the use of net proceeds therefrom as described in “Capitalization,” the notes would have been structurally subordinated to $6.9 billion of indebtedness of our subsidiaries, consisting of $870 million of indebtedness of Transwestern, $2.9 billion of indebtedness of Southern Union and its wholly owned subsidiary, Panhandle Eastern Pipe Line Company, LP, or Panhandle, $965 million of indebtedness of Sunoco and $2.2 billion of indebtedness of Sunoco Logistics. Please read “Description of Notes—Ranking” and “Description of Notes—Subsidiary Guarantees.” In addition, as of September 30, 2012, our unconsolidated joint ventures, FEP, Citrus and FGT, had outstanding $3.2 billion of indebtedness, consisting of

$600 million of borrowings outstanding under FEP’s term loan; $194 million of borrowings outstanding under Citrus’ $200 million revolving credit facility and $500 million of borrowings outstanding under Citrus’ construction term loan; and $30 million of borrowings outstanding under FGT’s $200 million revolving credit facility and $1.8 billion in aggregate principal amount of FGT’s senior notes. FEP is also a party to a $50 million revolving credit facility, which was undrawn as of September 30, 2012. Please read “Description of Other Indebtedness—Unconsolidated Joint Ventures.”

Optional Redemption

We may redeem the notes of each series for cash, in whole or in part at any time and from time to time, at our option at the applicable redemption price set forth under the heading “Description of Notes—Optional Redemption.”

Certain Covenants

We will issue the notes under a supplement to an indenture with U.S. Bank National Association, as trustee. The covenants in the indenture supplement include a limitation on liens and a restriction on sale-leaseback transactions. Each covenant is subject to a number of important exceptions, limitations and qualifications that are described in “Description of Notes—Certain Covenants.”

Use of Proceeds

We anticipate using the net proceeds of this offering to repay borrowings outstanding under our revolving credit facility. Please read “Use of Proceeds.”

Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a substantial portion of the net proceeds from this offering. Please read “Underwriting—Other Relationships.”

Further Issuances

We may create and issue additional notes ranking equally and ratably with any series of notes offered by this prospectus supplement in all respects, except for the issue date, issue price and in some cases, the first interest payment date, so that such additional notes will form a single series with the applicable series of notes offered by this prospectus supplement and will have substantially identical terms as such series, including with respect to ranking, redemption and otherwise.

Risk Factors

Investing in the notes involves risks. See “Risk Factors” beginning on page S-12 of this prospectus supplement and the risk factors set forth on page 4 of the accompanying prospectus and in our and Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2011, in each case as updated by our and Southern Union’s subsequent Quarterly Reports on Form 10-Q, together with all of the other information included in, or incorporated by reference into, this prospectus supplement and the accompanying prospectus before investing in the notes.

Ratio of Earnings to Fixed Charges

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

Year Ended
August 31,
2007

Four Months
Ended
December 31,
2007

Years Ended December 31,

Nine Months
Ended
September 30,
2012

2008

2009

2010

2011

Ratio of Earnings to Fixed Charges

4.28

4.31

3.95

2.92

2.31

2.39

3.67

For this ratio, “earnings” consist of:

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pre-tax income from continuing operations, before minority interest and equity in earnings of affiliates;

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amortization of capitalized interest;

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distributed income of equity investees; and

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fixed charges.

“Fixed charges” consist of:

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interest expensed;

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interest capitalized;

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amortized debt issuance costs; and

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estimated interest element of rentals.

An investment in the notes involves risks. You should consider carefully the following risk factors and the risk factors set forth beginning on page 4 of the accompanying prospectus and in our and Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2011, in each case as updated by our and Southern Union’s subsequent Quarterly Reports on Form 10-Q, 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 the notes.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to make required payments on the notes depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount of the notes at maturity, we may be required to adopt one or more alternatives, such as a refinancing of the notes. We cannot assure you that we would be able to refinance the notes.

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

Our subsidiaries own all of our operating assets. However, initially, none of our subsidiaries will guarantee our obligations with respect to the notes. Creditors of our subsidiaries that do not guarantee the notes will have claims, with respect to the assets of those subsidiaries, that rank structurally senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors must be satisfied prior to making any such distribution or payment to us in respect of our direct or indirect equity interests in such subsidiaries. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. Also, there are federal and state laws that could invalidate any guarantee of our subsidiaries that guarantee the notes in the future. If that were to occur, the claims of creditors of a guaranteeing subsidiary would also rank structurally senior to the notes, to the extent of the assets of that subsidiary. As of September 30, 2012, after giving effect to (i) the consummation of the Sunoco merger and Holdco restructuring, (ii) the Southern Union local distribution company dispositions and the use of the cash consideration therefrom as described in “Capitalization” and (iii) the public offering by Sunoco Logistics of $700 million in aggregate principal amount of senior notes and the use of the net proceeds therefrom as described in “Capitalization,” the notes would have been structurally subordinated to $6.9 billion of outstanding indebtedness of our subsidiaries, consisting of $870 million of indebtedness of Transwestern, $2.9 billion of indebtedness of Southern Union and Panhandle, $965 million of indebtedness of Sunoco and $2.2 billion of indebtedness of Sunoco Logistics. Furthermore, such subsidiaries will not be prohibited under the indenture from incurring additional indebtedness and any such indebtedness will rank structurally senior to the notes with respect to the assets of such subsidiaries. Our unconsolidated joint ventures, FEP, Citrus and FGT, are also parties to revolving and other credit facilities and have outstanding senior unsecured notes. As of September 30, 2012, FEP had $600 million of borrowings outstanding under its term loan and no amounts drawn under its $50 million revolving credit facility; Citrus had $194 million of borrowings outstanding under its $200 million revolving credit facility and $500 million of borrowings outstanding under its construction term loan; and FGT had $30 million of borrowings outstanding under its $200 million revolving credit facility and $1.8 billion in aggregate principal amount of senior notes. Please read “Description of Other Indebtedness—Unconsolidated Joint Ventures.”

In addition, holders of any future secured indebtedness of Energy Transfer Partners, L.P. would have claims with respect to the assets constituting collateral for such indebtedness that are prior to the claims of the holders of the notes. Energy Transfer Partners, L.P. (excluding its subsidiaries) does not currently have any secured indebtedness, but may have secured indebtedness in the future. In the event of a default on any secured indebtedness or our bankruptcy, liquidation or reorganization, our assets would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the notes. Accordingly, any such secured indebtedness would effectively rank senior to the notes to the extent of the value of the collateral securing the indebtedness. While the indenture governing the notes will place some limitations on our ability to create liens, there are significant exceptions to these limitations that will allow us to secure certain indebtedness without equally and ratably securing the notes. To the extent the value of the collateral is not sufficient to satisfy the secured indebtedness, the holders of that indebtedness would be entitled to share with the holders of the notes and the holders of other claims against us with respect to our other assets.

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

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

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

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

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

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for U.S. federal income tax purposes) are not subject to entity-level U.S. federal income tax, our acquisition of Sunoco and the Holdco restructuring have resulted in an increase in the proportion of our operations that are conducted through subsidiaries that are organized as C corporations. Such corporate subsidiaries are subject to corporate-level tax, the payment of which will reduce the cash otherwise available for servicing the notes and repaying them at maturity.

We expect to receive net proceeds of approximately $ million from the sale of the notes we are offering, after deducting the underwriting discounts and estimated offering expenses payable by us. We anticipate using the net proceeds of this offering to repay borrowings outstanding under our revolving credit facility.

As of January 8, 2013, an aggregate of $1.451 billion of borrowings were outstanding under our revolving credit facility, and there were $73.9 million of letters of credit outstanding. The weighted average interest rate on the total amount outstanding at January 8, 2013 was 1.649%. Our revolving credit facility matures on October 27, 2016. We used borrowings under our revolving credit facility to partially fund the cash portion of the merger consideration in the Sunoco merger and to fund growth capital expenditures and working capital requirements.

The following table sets forth our consolidated cash and cash equivalents and capitalization as of September 30, 2012:

The actual information in the table is derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, included in our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, and our unaudited pro forma financial statements related to the Sunoco merger and Holdco restructuring, including the accompanying notes, included in our Current Report on Form 8-K filed with the SEC on January 14, 2013, which are incorporated by reference in this prospectus supplement.

The table above does not include the outstanding indebtedness of our unconsolidated joint ventures, FEP, Citrus and FGT. As of December 31, 2012, FEP had no amounts drawn under its $50 million revolving credit facility and $600 million of borrowings outstanding under its term loan; Citrus had $144 million of borrowings outstanding under its $200 million revolving credit facility and $500 million of borrowings outstanding under its construction term loan; and FGT had $8 million of borrowings outstanding under its $200 million revolving credit facility and $1.8 billion in aggregate principal amount of senior notes.

Our indebtedness as of September 30, 2012 (not including debt of our subsidiaries) consisted of a revolving credit facility that allows for borrowings of up to $2.5 billion (expandable to $3.75 billion, subject to additional lender commitments) available through October 27, 2016, unless extended, and the following series of senior notes, which we refer to collectively as our existing senior notes:

In addition, in connection with the Sunoco merger and Holdco restructuring, we became a co-obligor of the following outstanding senior notes and debentures of Sunoco, which we refer to collectively as the Sunoco senior notes:

Our other subsidiaries, Transwestern, Southern Union, Panhandle and Sunoco Logistics (through its subsidiaries, Sunoco Operations and Sunoco Marketing), also have outstanding debt as described below.

The failure by us and our subsidiaries to comply with the various restrictive and affirmative covenants of our respective debt agreements could require us and our subsidiaries to repay outstanding debt prior to its maturity and could negatively affect our and our subsidiaries’ ability to incur additional debt. Various of our and our subsidiaries’ debt agreements require us and our subsidiaries to measure certain financial tests and covenants quarterly and, as of September 30, 2012, we and our subsidiaries were in compliance with all of the covenants, including the financial requirements, tests, limitations, and covenants related to financial ratios, under our respective existing debt agreements.

On October 27, 2011, we amended and restated our revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, swingline lender and an LC issuer, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Securities Inc., as joint lead

arrangers and joint book managers, and certain other agents and lenders. The credit facility provides for $2.5 billion of revolving credit capacity that is expandable to $3.75 billion at our option (subject to obtaining lender commitments for the additional borrowing capacity). The credit facility matures on October 27, 2016, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments under the credit facility). Amounts borrowed under the credit facility bear interest at a rate based on either a LIBOR rate or a base rate, at our option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for LIBOR rate loans ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.125% to 0.750%. The credit facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.5 billion unless expanded to $3.75 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. We may prepay the indebtedness under the credit facility at any time at our option without penalty (other than Eurodollar loan breakage costs, if any). The commitment fee payable on the unused portion of the credit facility varies based on our credit rating and ranges from 0.175% to 0.300%. Currently, the applicable rate for commitment fees is 0.25%.

The credit agreement relating to the credit facility contains covenants that limit (subject to certain exceptions) our and certain of our subsidiaries ability to, among other things, incur indebtedness; grant liens; enter into mergers; dispose of assets; make certain investments; make distributions during certain defaults and during any event of default; engage in business substantially different in nature than the business currently conducted by us and our subsidiaries; engage in transactions with affiliates; enter into restrictive agreements; and enter into speculative hedging contracts.

The credit agreement also contains a financial covenant that provides that on each date we make a distribution, the leverage ratio, as defined in the credit agreement, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified acquisition period, as defined in the credit agreement.

As of September 30, 2012, there was a balance of $492 million in revolving credit loans outstanding and $32 million in letters of credit issued. The weighted average interest rate on the total amount outstanding at September 30, 2012 was 1.72%. The total amount available for additional borrowing under the credit facility, as of September 30, 2012, was $1.98 billion. The indebtedness under the credit facility is unsecured and not guaranteed by any of our subsidiaries. The indebtedness under the credit facility is and will be pari passu with our other current and future unsecured debt.

Our existing senior notes and the Sunoco senior notes represent our senior unsecured obligations and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness, including the notes offered hereby. The existing senior notes and the Sunoco senior notes are not guaranteed by any of our subsidiaries, and therefore, structurally rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Each series of existing senior notes (other than the 4.650% Senior Notes due 2021, 5.20% Senior Notes due 2022, 6.050% Senior Notes due 2041 and 6.50% Senior Notes due 2042) is redeemable, in whole or in part, at any time at our option, at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. Each of the 4.650% Senior Notes due 2021, 5.20% Senior Notes due 2022, 6.050% Senior Notes due 2041 and 6.50% Senior Notes due 2042 is redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium if the redemption occurs before the date that is six months prior to maturity or (ii) at par if the redemption occurs on or after the date that is six months prior to maturity, in each case plus accrued and unpaid interest, if any, to the redemption date. The Sunoco senior notes (other than the 9.00% Debentures due 2024) are redeemable, in whole or in part, at any time at our

and Sunoco’s option, at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. The 9.00% Debentures due 2024 are not redeemable prior to maturity. Interest on our existing senior notes and the Sunoco senior notes is payable semi-annually.

The existing senior notes and the Sunoco senior notes were issued under indentures containing covenants that restrict our (and, with respect to the Sunoco senior notes, our and Sunoco’s) ability to, subject to certain exceptions, incur debt secured by liens; engage in sale and leaseback transactions; and merge or consolidate with another entity or sell substantially all of our assets.

As of September 30, 2012, Transwestern had the following outstanding series of unsecured notes, which we refer to collectively as the Transwestern notes:

No principal payments are required with respect to the Transwestern notes (except at maturity); however, Transwestern is required to make an offer to purchase all of the Transwestern notes upon a change of control of Transwestern, as defined in the indentures governing the Transwestern notes. Transwestern may prepay the Transwestern notes at any time subject to the payment of specified make-whole premiums. Interest is payable semi-annually on the Transwestern notes. The Transwestern notes rank pari passu with Transwestern’s other unsecured debt. The indentures governing the Transwestern notes contain provisions that, subject to certain exceptions, limit the amount of Transwestern’s debt, restrict its sale of assets and payment of dividends and require it to maintain certain debt to capitalization ratios.

Southern Union’s indebtedness consists of a $700 million revolving credit facility that matures on May 20, 2016 and the following senior and junior subordinated notes and first mortgage bonds:

Further, Southern Union has a $166 million note payable to ETE, which it entered into on March 26, 2012 in connection with its merger with ETE. This note is payable on or before March 25, 2013, and bears interest at 3.75% per annum.

The indebtedness of Panhandle, a wholly owned subsidiary of Southern Union, consists of a $455 million term loan due 2015 and the following series of senior notes:

Revolving Credit Facility. On March 26, 2012, Southern Union amended and restated its revolving credit facility with JPMorgan Chase Bank, National Association, as administrative agent, J.P. Morgan Securities LLC, PNC Capital Markets LLC and Wells Fargo Securities, LLC, as joint book-runners and co-lead arrangers, and certain other agents and lenders. The credit facility provides for $700 million of revolving credit capacity and matures on May 20, 2016. Borrowings under the revolving credit facility bear interest at LIBOR plus a margin, which varies from 1.125% to 2.25%, based on the Southern Union’s senior long-term unsecured debt ratings. Amounts under the revolving credit facility that remain undrawn are subject to a commitment fee payable quarterly in arrears at an annual rate that varies from 0.175% to 0.40% of such undrawn amounts, based on Southern Union’s senior long-term unsecured debt ratings. The revolving credit facility contains certain customary representations and warranties and affirmative and negative covenants, including certain limitations on the ability of Southern Union to, among other things, incur liens, incur indebtedness, sell or transfer assets or engage in acquisitions, mergers and/or consolidations, as well as the requirement to maintain a certain consolidated debt to earnings before interest, tax, depreciation and amortization (“EBITDA”) ratio. In addition, the revolving credit facility contains customary events of default. The indebtedness under the revolving credit facility is unsecured and not guaranteed by any of Southern Union’s subsidiaries. As of September 30, 2012, there was a balance of $251 million in revolving credit loans outstanding. The weighted average interest rate on the total amount outstanding as of September 30, 2012 was 1.83%. The total amount available for additional borrowing under the credit facility, as of September 30, 2012, was $449 million. We intend to use a portion of the cash consideration received from the Southern Union local distribution company dispositions to repay a portion of the borrowings outstanding under Southern Union’s revolving credit facility.

Senior Notes. Southern Union’s senior notes represent its senior unsecured obligations and rank equally with all of its other existing and future unsecured and unsubordinated indebtedness. Southern Union’s senior notes are not guaranteed by any of Southern Union’s subsidiaries, and therefore, structurally rank junior to all indebtedness and other liabilities of its existing and future subsidiaries. Southern Union’s senior notes are not redeemable prior to their respective maturity dates. Each series of Southern Union’s notes contains covenants that restrict Southern Union’s ability to, subject to certain exceptions, incur liens; enter into sale leaseback transactions; make restricted payments; enter into affiliate transactions; and sell or dispose of its assets to any of Southern Union’s subsidiaries.

Junior Notes. Southern Union’s obligations under the junior notes are subordinate and junior in right of payment to all of its other indebtedness, except any indebtedness that by its terms is subordinated to, or ranks on an equal basis with, the junior notes. In addition, because the notes are not guaranteed by any of Southern Union’s subsidiaries, the holders of junior notes generally have a junior position in right of payment to claims of creditors of Southern Union’s subsidiaries and joint ventures. Subject to Southern Union’s right to defer interest payments on the junior notes on one or more occasions for up to 10 consecutive years, interest on the junior notes is payable quarterly. Beginning on November 1, 2011, the interest rate is a floating rate based on three-month LIBOR plus 301.75 basis points, and is reset quarterly. Any deferred interest payments will accumulate additional interest at a rate equal to the interest rate then applicable to the junior notes, to the extent permitted by law.

Southern Union may redeem the junior notes, in whole or in part, at any time at par, plus accrued and unpaid interest, if any, to the redemption date. Unless Southern Union has paid all accrued and payable interest on the junior notes, or if an event of default has occurred and is continuing, the indenture governing the junior notes prohibits Southern Union and its subsidiaries from declaring or paying any dividends or distributions, or redeeming, purchasing, acquiring, or making a liquidation payment on any of

its capital stock; making any payment of principal of or interest or premium, if any, on or repaying, repurchasing or redeeming any of debt securities that rank equally with or junior in right of payment or upon liquidation to the junior notes; and making any guarantee payments on any guarantee of debt securities if the guarantee ranks equally with or junior in right of payment or upon liquidation to the junior notes. However, at any time, including during a period in which Southern Union has elected to defer interest payments or an event of default, Southern Union will be permitted to pay stock dividends or distributions in additional shares of capital stock; declare or pay a dividend in connection with the implementation of a stockholders’ rights plan, or issue stock under such a plan or repurchase such rights; and purchase common stock for issuance pursuant to any employee benefit plans or dividend reinvestment and direct stock purchase plans.

First Mortgage Bonds. In connection with its acquisition of Fall River Gas Company in 2000, Southern Union assumed Fall River Gas Company’s outstanding first mortgage bonds. The first mortgage bonds are secured by a lien on substantially all of the properties of Southern Union’s Fall River Gas division.

In connection with the Southern Union local distribution company dispositions, Laclede will assume Southern Union’s obligations under the first mortgage bonds.

Senior Notes. Panhandle’s senior notes represent its senior unsecured obligations and rank equally with all of its other existing and future unsecured and unsubordinated indebtedness. Panhandle’s existing senior notes are not guaranteed by any of its subsidiaries, and therefore, structurally rank junior to all indebtedness and other liabilities of its existing and future subsidiaries. Each series of Panhandle’s senior notes is redeemable in whole or in part, at the option of Panhandle at any time, at a price of 100% of their principal amount plus a make-whole premium and accrued and unpaid interest to the redemption date. The indenture governing Panhandle’s senior notes contains various covenants that limit, subject to certain exceptions, Panhandle’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, pay distributions on, or repurchase or redeem Panhandle’s equity interests, incur liens; enter into sale and leaseback transactions, enter into certain types of affiliates transactions and dispose of assets.

Term Loan. On February 23, 2012, Southern Union refinanced the term loan of Panhandle’s wholly owned subsidiary, Trunkline LNG, with a $455 million unsecured term loan that matures on February 23, 2015. Both Panhandle and Trunkline LNG Company LLC, a wholly owned subsidiary of Panhandle, are guarantors under the term loan. Amounts borrowed under the term loan bear interest at a rate based on either a LIBOR rate or a base rate, at Trunkline LNG’s option, plus an applicable margin. The applicable margin used in connection with the interest rates are based on the credit ratings assigned to Panhandle’s senior, unsecured, non-credit enhanced long-term debt. The applicable margin for LIBOR rate loans ranges from 1.125% to 2.25% and the applicable margin for base rate loans ranges from 0.125% to 1.25%. Trunkline LNG may prepay the term loan in whole or ratably in part, together with accrued interest to the date of such prepayment, without penalty (other than Eurodollar loan breakage costs, if any).

The term loan includes covenants that limit (subject to certain exceptions) Panhandle’s and Trunkline LNG’s ability to, among other things, pay dividends and other restricted payments, enter into affiliate transactions, incur additional debt, sell asset and liens. Additionally, the term loan includes a financial covenant that requires Panhandle to maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 5.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended. As of September 30, 2012, the balance of the term loan was $455 million, with an effective interest rate of 1.84%. We intend to use a portion of the cash consideration received from the Southern Union local distribution company dispositions to repay a portion of the borrowings outstanding under the term loan.

Sunoco Logistics’ indebtedness consists of a $350 million unsecured credit facility of its wholly owned subsidiary, Sunoco Operations, maturing in August 2016, or the 2016 credit facility, and a $200 million 364-day revolving unsecured credit facility of its wholly owned subsidiary, Sunoco Marketing, maturing in August 2013, or the 2013 credit facility. Additionally, Sunoco Operations has outstanding the following series of senior notes:

West Texas Gulf Pipe Line Company, or West Texas Gulf, an entity in which Sunoco Logistics has a controlling financial interest, also has a $35 million revolving credit facility maturing in April 2015.

2016 Credit Facility. On August 22, 2011, Sunoco Operations entered into the 2016 credit facility with Citibank, N.A., as administrative agent, swing line lender, lender and L/C issuer, and Citigroup Global Markets Inc. and Barclays Capital, as joint lead arrangers and book runners, and certain other agents and lenders. The 2016 credit facility provides for $350 million of revolving credit capacity, with a $100 million sub-limit for letters of credit and a $50 million sub-limit for swing line loans, and matures on August 22, 2016. Sunoco Operations’ obligations under the 2016 credit facility are guaranteed by Sunoco Logistics. Amounts borrowed under the 2016 credit facility bear interest at a rate based on either a LIBOR rate or a base rate, at Sunoco Operations’ option, plus an applicable rate. The applicable rate used in connection with the interest rates and facility fees, respectively, are based on the credit ratings assigned to Sunoco Operations’ non-credit enhanced, senior unsecured long-term debt. The applicable rate for LIBOR rate loans ranges from 0.850% to 1.650% and the applicable rate for base rate loans ranges from 0% to 0.650%. The applicable rate for the facility fee payable on the unused portion of the 2016 credit facility ranges from 0.150% to 0.350%. Sunoco Operations may prepay the indebtedness under the 2016 credit facility at any time at its option without premium or penalty.

The credit agreement relating to the 2016 credit facility contains covenants that limit (subject to certain exceptions) the ability of Sunoco Logistics, Sunoco Operations and their respective subsidiaries to, among other things, incur indebtedness; grant liens; make loans, acquisitions and investments; make any material change to the nature of their business; enter into a merger or sale of assets; and enter into speculative hedging contracts. The credit agreement also contains a financial covenant that provides the leverage ratio, as defined in the credit agreement, of Sunoco Logistics shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified acquisition period.

As of September 30, 2012, there was a balance of $96 million in revolving credit loans outstanding and no letters of credit had been issued under the 2016 credit facility. The weighted average interest rate on the total amount outstanding at September 30, 2012 was 1.52%. On January 10, 2013, Sunoco Logistics repaid in full the balance outstanding under the 2016 credit facility with the net proceeds from Sunoco Operations’ public notes offering.

2013 Credit Facility. Sunoco Marketing entered into the 2013 credit facility with Citibank, N.A., as administrative agent, Citigroup Global Markets Inc. and Barclays Bank PLC, as joint lead arrangers and

book runners, and certain other agents and lenders on August 14, 2012. The 2013 credit facility provides for $200 million of revolving credit capacity and matures on August 12, 2013. Sunoco Marketing’s obligations under the 2013 credit facility are guaranteed by Sunoco Operations and Sunoco Logistics. Amounts borrowed under the 2013 credit facility bear interest at a rate based on either a LIBOR rate or a base rate, at Sunoco Marketing’s option, plus an applicable rate. The applicable rate used in connection with the interest rates and facility fees, respectively, are based on the credit ratings assigned to Sunoco Operations’ non-credit enhanced, senior unsecured long-term debt. The applicable rate for LIBOR rate loans ranges from 0.940% to 1.700% and the applicable rate for base rate loans ranges from 0% to 0.700%. The applicable rate for the facility fee payable on the unused portion of the 2013 credit facility ranges from 0.060% to 0.175%. Sunoco Marketing may prepay the indebtedness under the 2013 credit facility at any time at its option without premium or penalty.

The 2013 credit facility contains similar covenants as those contained in the 2016 credit facility described above. As of September 30, 2012, outstanding borrowings under the 2013 credit facility were $74 million. The weighted average interest rate on the total amount outstanding at September 30, 2012 was 1.49%. On January 10, 2013, Sunoco Marketing repaid in full the balance outstanding under the 2013 credit facility with the net proceeds from Sunoco Operations’ public notes offering.

Senior Notes. Sunoco Operations’ obligations under its senior notes are guaranteed by Sunoco Logistics. The Sunoco Operations’ senior notes represent Sunoco Operations’ senior unsecured obligations and rank equally in right of payment with all of its existing and future unsecured and unsubordinated indebtedness, including debt under the 2016 credit facility and the 2013 credit facility. Sunoco Logistics’ guarantee of the senior notes ranks equally in right of payment with its existing and future unsecured and unsubordinated indebtedness, including its guarantee of debt under the 2016 credit facility and the 2013 credit facility. Each series of Sunoco Operations’ senior notes (other than the 3.45% Senior Notes due 2023 and the 4.95% Senior Notes due 2043) is redeemable, in whole or in part, at any time at Sunoco Operations’ option, at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. Each of the 3.45% Senior Notes due 2023 and the 4.95% Senior Notes due 2043 is redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium if the redemption occurs before the date that is six months prior to maturity or (ii) at par if the redemption occurs on or after the date that is six months prior to maturity, in each case plus accrued and unpaid interest, if any, to the redemption date. The senior notes were issued under an indenture containing covenants that limit, subject to certain exceptions, the ability of Sunoco Operations and its subsidiaries to create liens and engage in sale and leaseback transactions; and merger or consolidate with another entity or sell substantially all of their assets.

Our unconsolidated joint ventures, FEP, Citrus and FGT, are parties to certain debt agreements as described below.

FEP Term Loan. On July 28, 2011, FEP entered into a $600 million term loan agreement that matures on July 28, 2013. FEP may extend the maturity date by one year upon written notice to the administrative agent and the payment of an extension fee that varies based on FEP’s leverage ratio (as defined in the term loan agreement). Amounts borrowed under the term loan bear interest at a rate based on either a LIBOR rate or a base rate, at FEP’s option, plus an applicable margin. As of September 30, 2012, the balance of the term loan was $600 million with an effective interest rate of 2.08%.

FEP Revolving Credit Facility. FEP also entered into a $50 million revolving credit facility on July 28, 2011, which matures on July 28, 2015. Borrowings under the revolving credit facility bear interest at LIBOR or a base rate, at FEP’s option, plus an applicable margin based on FEP’s long-term senior

unsecured non-credit enhanced debt rating. The revolving credit facility has a swingline loan option under which the aggregate principal amount of outstanding swingline loans cannot exceed $15 million and the outstanding principal amount of each lender’s loans (including swingline loans) cannot exceed the total commitments under the facility. As of September 30, 2012, there were no borrowings under the revolving credit facility.

Revolving Credit Facility. Citrus entered into a $200 million revolving credit facility on June 29, 2012. Borrowings under the revolving credit facility bear interest at LIBOR or a base rate, at Citrus’ option, plus an applicable margin based on FGT’s long-term senior unsecured non-credit enhanced debt rating. The revolving credit facility has a swingline loan option under which the aggregate principal amount of outstanding swingline loans cannot exceed $25 million and the outstanding principal amount of each lender’s loans (including swingline loans) cannot exceed the total commitments under the facility. Citrus’ obligations under the revolving credit facility are guaranteed by FGT. The revolving credit facility matures on November 2, 2015, subject to Citrus’ right to extend the maturity date by one year (which right may not be exercised more than twice). As of September 30, 2012, there were $194 million of borrowings outstanding under such facility with a weighted average interest rate of 1.61%.

Construction Term Loan. Citrus entered into a $500 million construction term loan with Pipeline Funding Company, LLC on February 5, 2008 in order to finance the construction of certain expansion projects on FGT’s pipelines. The term loan matures on October 8, 2029, and borrowings under the loan bear interest at the Treasury rate plus an applicable margin. As of September 30, 2012, the balance of the term loan was $500 million, with an effective interest rate of 9.39%.

Revolving Credit Facility. FGT entered into a $200 million credit agreement on June 29, 2012. Borrowings under the revolving credit facility bear interest at LIBOR or a base rate, at FGT’s option, plus an applicable margin based on FGT’s long-term senior unsecured non-credit enhanced debt rating. The revolving credit facility has a swingline loan option under which the aggregate principal amount of outstanding swingline loans cannot exceed $25 million and the outstanding principal amount of each lender’s loans (including swingline loans) cannot exceed the total commitments under the facility. Additionally, FGT may request letters of credit under the facility not exceeding $50 million. The revolving credit facility matures on November 2, 2015, subject to FGT’s right to extend the maturity date by one year (which right may not be exercised more than twice). As of September 30, 2012, there were $30 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 1.60%.

Senior Notes. FGT has outstanding $1.8 billion in aggregate principal amount of senior notes, consisting of the following:

The senior notes are FGT’s senior, unsecured general obligations, and the indentures under which such notes were issued contain customary terms, events of default and covenants.

Energy Transfer will issue the notes under an indenture dated as of January 18, 2005 among itself, the subsidiaries of Energy Transfer named therein and U.S. Bank National Association (as successor-by-merger to Wachovia Bank, National Association), as trustee, as supplemented by a supplemental indenture creating the notes (as so supplemented, the “indenture”). This description is a summary of the material provisions of the notes and the indenture. This description does not restate those agreements and instruments in their entirety. You should refer to the notes and the indenture, forms of which are available as set forth below under “Where you can find more information,” for a complete description of our obligations and your rights.

You can find the definitions of various terms used in this description under “—Certain Definitions” below. In this description, the terms “Energy Transfer,” “we,” “us” and “our” refer only to Energy Transfer Partners, L.P. and not to any of its Subsidiaries.

The 2023 notes and 2043 notes each constitute a separate series of debt securities under the indenture. The indenture does not limit the amount of debt securities we may issue under the indenture from time to time in one or more series. Currently, we have the following series of notes outstanding under the indenture (collectively, the “existing senior notes”):

We may in the future issue additional debt securities under the indenture in addition to the notes.

Interest on the notes will accrue from and including , 2013 or from and including the most recent interest payment date to which interest has been paid or provided for. We will pay interest in cash semiannually in arrears on and of each year, beginning , 2013. We will make interest payments to the persons in whose names the notes are registered at the close of business on or , as applicable, before the next interest payment date. Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months. If any interest payment date falls on a day that is not a business day, the payment will be made on the next business day, and no interest will accrue on the amount of interest due on that interest payment date for the period from and after the interest payment date to the date of payment.

We may from time to time, without notice to or the consent of the holders of the notes, create and issue additional notes having the same terms as either of the series of notes offered by this prospectus supplement and accompanying prospectus, except for issue date, issue price and in some cases, the first interest payment date. Additional notes issued in this manner will form a single series with the previously issued and outstanding notes of such series.

Prior to , 2022, with respect to the 2023 notes, and , 2042, with respect to the 2043 notes, the respective notes will be redeemable, at our option, at any time in whole, or from time to time in part, at a price equal to the greater of:

plus, in either case, accrued and unpaid interest to, but excluding, the redemption date.

At any time on or after , 2022, with respect to the 2023 notes, and , 2042, with respect to the 2043 notes, the respective notes will be redeemable in whole or in part, at our option, at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest thereon to, but excluding, the redemption date.

The actual redemption price, calculated as provided below, will be calculated and certified to the trustee and us by the Independent Investment Banker.

Notes called for redemption become due on the redemption date. Notices of redemption will be mailed at least 30 but not more than 60 days before the redemption date to each holder of the notes to be redeemed at its registered address. The notice of redemption for the notes will state, among other things, the amount of notes to be redeemed, the redemption date, the method of calculating the redemption price and each place that payment will be made upon presentation and surrender of notes to be redeemed. Unless we default in payment of the redemption price, interest will cease to accrue on any notes that have been called for redemption on the redemption date. If less than all of the notes of a series are redeemed at any time, the trustee will select the notes to be redeemed on a pro rata basis, by lot or by any other method the trustee deems fair and appropriate.

For purposes of determining the redemption price, the following definitions are applicable:

“Treasury Yield” means, with respect to any redemption date applicable to the notes, (a) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities,” for the maturity corresponding to the Comparable Treasury Issue; or (b) if the release (or any successor release) is not published during the week preceding the calculation date or does not contain these yields, the rate per annum equal to the semi-annual equivalent yield to maturity (computed as of the third business day immediately preceding such redemption date) of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the applicable Comparable Treasury Price for such redemption date.

“Comparable Treasury Issue” means the United States Treasury security selected by the Independent Investment Banker as having a maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes to be redeemed; provided, however, that if no maturity is within three months before or after the maturity date for such notes, yields for the two published maturities most closely corresponding to such United States Treasury security will be determined and the treasury rate will be interpolated or extrapolated from those yields on a straight line basis rounding to the nearest month.

“Comparable Treasury Price” means, with respect to any redemption date, (a) the average of the Reference Treasury Dealer Quotations for the redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (b) if the Independent Investment Banker obtains fewer than four Reference Treasury Dealer Quotations, the average of all such quotations.

“Independent Investment Banker” means Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (and their respective successors) or, if any such firm is not willing and able to select the applicable Comparable Treasury Issue, an independent investment banking institution of national standing appointed by the trustee and reasonably acceptable to Energy Transfer.

“Reference Treasury Dealer” means (a) each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC and their respective successors, and (b) one other primary U.S. government securities dealer in the United States selected by Energy Transfer (each, a “Primary Treasury Dealer”); provided, however, that if any of the foregoing shall resign as a Reference Treasury Dealer or cease to be a U.S. government securities dealer, Energy Transfer will substitute therefor another Primary Treasury Dealer.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date for the notes, an average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue for the notes to be redeemed (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

The notes initially will not be guaranteed by any of our Subsidiaries. However, if at any time following the issuance of the notes, any Subsidiary of Energy Transfer guarantees, becomes a co-obligor with respect to or otherwise provides direct credit support for any obligations of Energy Transfer or any of its other Subsidiaries under the Credit Agreement, then Energy Transfer will cause such Subsidiary to promptly execute and deliver to the trustee a supplemental indenture in a form satisfactory to the trustee pursuant to which such Subsidiary guarantees Energy Transfer’s obligations with respect to the notes on the terms provided for in the indenture.

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to the notes as described below under

“—Defeasance and Discharge,” then any Subsidiary Guarantor will be released. 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 its guarantee:

If at any time following any release of a Subsidiary Guarantor from its guarantee of the notes pursuant to the third bullet point in the preceding paragraph, the Subsidiary Guarantor again guarantees, becomes a co-obligor with respect to or otherwise provides direct credit support for any obligations of Energy Transfer or any of its Subsidiaries under the Credit Agreement, then Energy Transfer will cause the Subsidiary Guarantor to again guarantee the notes in accordance with the indenture.

The notes will be unsecured, unless we are required to secure them pursuant to the limitations on liens covenant described below under “—Certain Covenants—Limitations on Liens.” The notes will also be the unsubordinated obligations of Energy Transfer and will rank equally with all other existing and future unsubordinated indebtedness of Energy Transfer. Each guarantee, if any, of the notes will be an unsecured and unsubordinated obligation of the Subsidiary Guarantor and will rank equally with all other existing and future unsubordinated indebtedness of the Subsidiary Guarantor. The notes and each guarantee, if any, will effectively rank junior to any future indebtedness of Energy Transfer and any Subsidiary Guarantor that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the notes will structurally rank junior to all indebtedness and other liabilities of Energy Transfer’s existing and future Subsidiaries that are not Subsidiary Guarantors.

As of September 30, 2012, after giving effect to (i) the consummation of the Sunoco merger and Holdco restructuring, (ii) the Southern Union local distribution company dispositions and the use of the cash consideration therefrom as described in “Capitalization”, (iii) the public offering by Sunoco Logistics of $700 million in aggregate principal amount of senior notes and the use of net proceeds therefrom as described in “Capitalization” and (iv) this offering and the use of net proceeds therefrom, Energy Transfer, excluding its Subsidiaries, would have had $ billion of indebtedness, all of which would have been unsecured, unsubordinated indebtedness consisting entirely of the notes, the existing senior notes, the Sunoco senior notes and the obligations under the Credit Agreement. Initially, none of Energy Transfer’s Subsidiaries will guarantee the notes. Energy Transfer’s Subsidiaries, Transwestern, Southern Union, Panhandle and Sunoco Logistics, have outstanding debt securities. As of September 30, 2012, after giving effect to (i) the consummation of the Sunoco merger and Holdco restructuring, (ii) the Southern Union local distribution company dispositions and the use of the cash consideration therefrom as described in “Capitalization” and (iii) the public offering by Sunoco Logistics of $700 million in aggregate principal amount of senior notes and the use of net proceeds therefrom as described in “Capitalization”, the notes would have been structurally subordinated to $6.9 billion of indebtedness of these Subsidiaries.

We are not required to make any mandatory redemption or sinking fund payments with respect to the notes.

Except as set forth below, neither Energy Transfer nor any of its Subsidiaries is restricted by the indenture from incurring any type of indebtedness or other obligation, from paying dividends or making distributions on its partnership or other equity interests or from purchasing or redeeming its partnership or other equity interests. The indenture does not require the maintenance of any financial ratios or specified levels of net worth or liquidity. In addition, the indenture does not contain any provisions that would require Energy Transfer to repurchase or redeem or otherwise modify the terms of the notes upon a change in control or other events involving Energy Transfer that could adversely affect the creditworthiness of Energy Transfer.

Limitations on Liens. Energy Transfer will not, nor will it permit any of its Subsidiaries to, create, assume, incur or suffer to exist any mortgage, lien, security interest, pledge, charge or other encumbrance (“liens”) upon any Principal Property or upon any capital stock of any Restricted Subsidiary, whether owned on the date of the supplemental indenture creating the notes or thereafter acquired, to secure any Indebtedness of Energy Transfer or any other Person (other than the notes), without in any such case making effective provisions whereby all of the outstanding notes are secured equally and ratably with, or prior to, such Indebtedness so long as such Indebtedness is so secured.

Notwithstanding the foregoing, under the indenture, Energy Transfer may, and may permit any of its Subsidiaries to, create, assume, incur, or suffer to exist without securing the notes (a) any Permitted Lien, (b) any lien upon any Principal Property or capital stock of a Restricted Subsidiary to secure Indebtedness of Energy Transfer or any other Person, provided that the aggregate principal amount of all Indebtedness then outstanding secured by such lien and all similar liens under this clause (b), together with all Attributable Indebtedness from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by clauses (1) through (4), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below), does not exceed 10% of Consolidated Net Tangible Assets or (c) any lien upon (i) any Principal Property that was not owned by Energy Transfer or any of its Subsidiaries on the date of the supplemental indenture creating the notes or (ii) the capital stock of any Restricted Subsidiary that owns no Principal Property that was owned by Energy Transfer or any of its Subsidiaries on the date of the supplemental indenture creating the notes, in each case owned by a Subsidiary of Energy Transfer (an “Excluded Subsidiary”) that (A) is not, and is not required to be, a Subsidiary Guarantor and (B) has not granted any liens on any of its property securing Indebtedness with recourse to Energy Transfer or any Subsidiary of Energy Transfer other than such Excluded Subsidiary or any other Excluded Subsidiary.

Restriction on Sale-Leasebacks. Energy Transfer will not, and will not permit any Subsidiary to, engage in the sale or transfer by Energy Transfer or any of its Subsidiaries of any Principal Property to a Person (other than Energy Transfer or a Subsidiary) and the taking back by Energy Transfer or its Subsidiary, as the case may be, of a lease of such Principal Property (a “Sale-Leaseback Transaction”), unless:

(1) such Sale-Leaseback Transaction occurs within one year from the date of completion of the acquisition of the Principal Property subject thereto or the date of the completion of construction, development or substantial repair or improvement, or commencement of full operations on such Principal Property, whichever is later;

(2) the Sale-Leaseback Transaction involves a lease for a period, including renewals, of not more than three years;

(3) Energy Transfer or such Subsidiary would be entitled to incur Indebtedness secured by a lien on the Principal Property subject thereto in a principal amount equal to or exceeding the Attributable Indebtedness from such Sale-Leaseback Transaction without equally and ratably securing the notes; or

(4) Energy Transfer or such Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the Attributable

Indebtedness from such Sale-Leaseback Transaction to (a) the prepayment, repayment, redemption, reduction or retirement of any Indebtedness of Energy Transfer or any of its Subsidiaries that is not subordinated to the notes or any guarantee, or (b) the expenditure or expenditures for Principal Property used or to be used in the ordinary course of business of Energy Transfer or its Subsidiaries.

Notwithstanding the foregoing, Energy Transfer may, and may permit any Subsidiary to, effect any Sale-Leaseback Transaction that is not excepted by clauses (1) through (4), inclusive, of the preceding paragraph provided that the Attributable Indebtedness from such Sale-Leaseback Transaction, together with the aggregate principal amount of outstanding Indebtedness (other than the notes) secured by liens other than Permitted Liens upon Principal Properties, does not exceed 10% of Consolidated Net Tangible Assets.

Merger, Consolidation or Sale of Assets. Energy Transfer shall not consolidate with or merge into any Person or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to any Person unless:

(1) the Person formed by or resulting from any such consolidation or merger or to which such assets have been transferred (the “successor”) is Energy Transfer or expressly assumes by supplemental indenture all of Energy Transfer’s obligations and liabilities under the indenture and the notes;

(2) the successor is organized under the laws of the United States, any state or the District of Columbia;

(3) immediately after giving effect to the transaction no Default or Event of Default has occurred and is continuing; and

(4) Energy Transfer has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or transfer complies with the indenture.

The successor will be substituted for Energy Transfer in the indenture with the same effect as if it had been an original party to the indenture. Thereafter, the successor may exercise the rights and powers of Energy Transfer under the indenture. If Energy Transfer conveys or transfers all or substantially all of its assets, it will be released from all liabilities and obligations under the indenture and under the notes except that no such release will occur in the case of a lease of all or substantially all of its assets.

Each of the following is an “Event of Default” under the indenture with respect to the notes of each series:

(1) a default in any payment of interest on such notes when due that continues for 30 days;

(2) a default in the payment of principal of or premium, if any, on such notes when due at their stated maturity, upon redemption, upon declaration or otherwise;

(3) a failure by Energy Transfer or any Subsidiary Guarantor to comply with its other covenants or agreements in the indenture for 60 days after written notice of default given by the trustee or the holders of at least 25% in aggregate principal amount of the outstanding notes;

(4) certain events of bankruptcy, insolvency or reorganization of Energy Transfer or any Subsidiary Guarantor as more fully described in the indenture (the “bankruptcy provisions”);

(5) any guarantee of a Subsidiary Guarantor ceases to be in full force and effect, is declared null and void or is found to be invalid in a judicial proceeding or any Subsidiary Guarantor denies or disaffirms its obligations under the indenture or its guarantee; or

(6) any Indebtedness of Energy Transfer or any Subsidiary Guarantor is not paid within any applicable grace period after final maturity or is accelerated by the holders thereof because of a default and the total amount of such Indebtedness unpaid or accelerated exceeds $25,000,000.

An Event of Default for the notes will not necessarily constitute an Event of Default for any other series of debt securities issued under the indenture, and an Event of Default for any such other series of debt securities will not necessarily constitute an Event of Default for any series of the notes. Further, an event of default under other indebtedness of Energy Transfer or its Subsidiaries will not necessarily constitute a Default or an Event of Default for the notes. If an Event of Default (other than an Event of Default described in clause (4) above) with respect to the notes of any series occurs and is continuing, the trustee by notice to Energy Transfer, or the holders of at least 25% in principal amount of the outstanding notes of such series by notice to Energy Transfer and the trustee, may, and the trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the notes of such series to be due and payable. Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. The indenture provides that if an Event of Default described in clause (4) above occurs, the principal of, premium, if any, and accrued and unpaid interest on the notes will become and be immediately due and payable without any declaration of acceleration, notice or other act on the part of the trustee or any holders. However, the effect of such provision may be limited by applicable law.

The holders of a majority in principal amount of the outstanding notes of the applicable series may, by written notice to the trustee, rescind any acceleration with respect to the notes of such series and annul its consequences if rescission would not conflict with any judgment or decree of a court of competent jurisdiction and all existing Events of Default with respect to the notes of such series, other than the nonpayment of the principal of, premium, if any, and interest on the notes that have become due solely by such acceleration, have been cured or waived.

Subject to the provisions of the indenture relating to the duties of the trustee if an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any of the holders of notes, unless such holders have offered to the trustee reasonable indemnity or security against any cost, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder of notes may pursue any remedy with respect to the indenture or the notes, unless:

(1) such holder has previously given the trustee notice that an Event of Default with respect to the notes is continuing;

(2) holders of at least 25% in principal amount of the outstanding notes of the applicable series have requested in writing that the trustee pursue the remedy;

(3) such holders have offered the trustee reasonable security or indemnity against any cost, liability or expense;

(4) the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding notes of the applicable series have not given the trustee a direction that, in the opinion of the trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding notes of the applicable series have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or of exercising any trust or power conferred on the trustee with respect to the notes of such series. The trustee, however, may refuse to follow any direction that conflicts with law or the indenture or that the trustee determines is unduly prejudicial to the rights of any other holder of notes or that would involve the trustee in personal liability.

The indenture provides that if a Default (that is, an event that is, or after notice or the passage of time would be, an Event of Default) with respect to the notes occurs and is continuing and is known to the trustee, the trustee must mail to each holder of notes notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, and premium, if any, or interest on the notes, the trustee may withhold such notice, but only if and so long as the trustee in good faith determines that withholding notice is in the interests of the holders of notes. In addition, Energy Transfer is required to deliver to the trustee, within 120 days after the end of each fiscal year, an officers’ certificate as to compliance with all covenants under the indenture and indicating whether the signers thereof know of any Default or Event of Default that occurred during the previous year. Energy Transfer also is required to deliver to the trustee, within 30 days after the occurrence thereof, an officers’ certificate specifying any Default or Event of Default, its status and what action Energy Transfer is taking or proposes to take in respect thereof.

Amendments of the indenture may be made by Energy Transfer, the Subsidiary Guarantors, if any, and the trustee with the written consent of the holders of a majority in principal amount of the debt securities of each affected series then outstanding under the indenture (including consents obtained in connection with a tender offer or exchange offer for debt securities). However, without the consent of each holder of an affected note, no amendment may, among other things:

(1) reduce the percentage in principal amount of notes whose holders must consent to an amendment;

(4) reduce the premium payable upon the redemption of any note as described above under “—Optional Redemption;”

(6) impair the right of any holder to receive payment of the principal of and premium, if any, and interest on such holder’s note or to institute suit for the enforcement of any payment on or with respect to such holder’s note;

(7) waive a Continuing Default (as defined in the indenture) or Event of Default in the payment of principal and premium, if any, and interest with respect to such holder’s note;

(8) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(9) release any security that may have been granted in respect of the notes other than in accordance with the indenture; or

(10) release the guarantee of any Subsidiary Guarantor other than in accordance with the indenture or modify its guarantee in any manner adverse to the holders.

The holders of a majority in principal amount of the outstanding notes of any series may waive compliance by Energy Transfer with certain restrictive covenants on behalf of all holders of notes of such

series, including those described under “—Certain Covenants— Limitations on Liens” and “—Certain Covenants— Restriction on Sale-Leasebacks.” The holders of a majority in principal amount of the outstanding notes of any series, on behalf of all such holders, may waive any past or existing default or Event of Default with respect to the notes of such series (including any such waiver obtained in connection with a tender offer or exchange offer for the notes), except a default or Event of Default in the payment of principal, premium or interest or in respect of a provision that under the indenture cannot be modified or amended without the consent of the holder of each outstanding note affected. A waiver by the holders of notes of any series of compliance with a covenant, a default or an Event of Default will not constitute a waiver of compliance with such covenant or such default or Event of Default with respect to any other series of debt securities issued under the indenture to which such covenant, default or Event of Default applies.

Without the consent of any holder, Energy Transfer, the Subsidiary Guarantors, if any, and the trustee may amend the indenture to:

(2) provide for the assumption by a successor of the obligations of Energy Transfer under the indenture;

(3) provide for uncertificated notes in addition to or in place of certificated notes;

(4) provide for the addition of any Subsidiary as a Subsidiary Guarantor, or to reflect the release of any Subsidiary Guarantor, in either case as provided in the indenture;

(6) add to the covenants of Energy Transfer or any Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon Energy Transfer or any Subsidiary Guarantor;

(8) make any change that does not adversely affect the rights under the indenture of any holder;

(9) supplement any of the provisions of the indenture to facilitate the defeasance and discharge of notes pursuant to the terms of the indentures;

(10) comply with any requirement of the SEC in connection with the qualification of the indenture under the Trust Indenture Act; and

The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment with the consent of the holders under the indenture becomes effective, Energy Transfer is required to mail to all holders of notes a notice briefly describing such amendment. However, the failure to give such notice to all such holders, or any defect therein, will not impair or affect the validity of the amendment.

Energy Transfer at any time may terminate all its obligations under the indenture as they relate to the notes of any series (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer of or exchange the notes, to replace mutilated, destroyed, lost or stolen notes and to maintain a registrar and paying agent in respect of the notes.

Energy Transfer at any time may terminate its obligations under the covenants described under “—Certain Covenants” (other than “Merger, Consolidation or Sale of Assets”) and the bankruptcy provisions

with respect to each Subsidiary Guarantor, the guarantee provision and the cross-acceleration provision described under “—Events of Default” above with respect to the notes of any series (“covenant defeasance”).

Energy Transfer may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If Energy Transfer exercises its legal defeasance option, payment of the notes of the applicable series may not be accelerated because of an Event of Default. If Energy Transfer exercises its covenant defeasance option for the notes, payment of the notes of the applicable series may not be accelerated because of an Event of Default specified in clause (3), (4) (with respect only to a Subsidiary Guarantor), (5) or (6) under “—Events of Default” above. If Energy Transfer exercises either its legal defeasance option or its covenant defeasance option, each guarantee will terminate with respect to the notes of the applicable series and any security that may have been granted with respect to the notes of the applicable series will be released.

In order to exercise either defeasance option, Energy Transfer must irrevocably deposit in trust (the “defeasance trust”) with the trustee money, U.S. Government Obligations (as defined in the indenture) or a combination thereof for the payment of principal, premium, if any, and interest on the notes of the applicable series to redemption or stated maturity, as the case may be, and must comply with certain other conditions, including delivery to the trustee of an opinion of counsel (subject to customary exceptions and exclusions) to the effect that holders of the notes will not recognize income, gain or loss for federal income tax purposes as a result of such defeasance and will be subject to federal income tax on the same amounts and in the same manner and at the same times as would have been the case if such defeasance had not occurred. In the case of legal defeasance only, such opinion of counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

In the event of any legal defeasance, holders of the notes of the applicable series would be entitled to look only to the trust fund for payment of principal of and any premium and interest on their notes until maturity.

Although the amount of money and U.S. Government Obligations on deposit with the trustee would be intended to be sufficient to pay amounts due on the notes at the time of their stated maturity, if Energy Transfer exercises its covenant defeasance option for the notes and the notes are declared due and payable because of the occurrence of an Event of Default, such amount may not be sufficient to pay amounts due on the notes at the time of the acceleration resulting from such Event of Default. Energy Transfer would remain liable for such payments, however.

In addition, Energy Transfer may discharge all its obligations under the indenture with respect to the notes of any series, other than its obligation to register the transfer of and exchange notes, provided that either:

We have obtained the information in this section concerning The Depository Trust Company (“DTC”) and its book-entry systems and procedures from DTC, but we take no responsibility for the accuracy of this information. In addition, the description in this section reflects our understanding of the rules and procedures of DTC as they are currently in effect. DTC could change its rules and procedures at any time.

The notes will initially be represented by one or more fully registered global notes. Each such global note will be deposited with, or on behalf of, DTC or any successor thereto and registered in the name of

Cede & Co. (DTC’s nominee). You may hold your interests in the global notes through DTC either as a participant in DTC or indirectly through organizations that are participants in DTC.

So long as DTC or its nominee is the registered owner of the global securities representing the notes, DTC or such nominee will be considered the sole owner and holder of the notes for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in the notes will not be entitled to have the notes registered in their names, will not receive or be entitled to receive physical delivery of the notes in definitive form and will not be considered the owners or holders of the notes under the indenture, including for purposes of receiving any reports delivered by us or the trustee pursuant to the indenture. Accordingly, each person owning a beneficial interest in a note must rely on the procedures of DTC or its nominee and, if such person is not a participant, on the procedures of the participant through which such person owns its interest, in order to exercise any rights of a holder of notes.

The Depository Trust Company. DTC will act as securities depositary for the notes. The notes will be issued as fully registered notes registered in the name of Cede & Co. DTC has advised us as follows: DTC is

DTC holds securities that its direct participants deposit with DTC. DTC facilitates the settlement among direct participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in direct participants’ accounts, thereby eliminating the need for physical movement of securities certificates.

Direct participants of DTC include securities brokers and dealers (including the underwriters), banks, trust companies, clearing corporations, and certain other organizations. DTC is owned by a number of its direct participants. Access to the DTC system is also available to securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly.

If you are not a direct participant or an indirect participant and you wish to purchase, sell or otherwise transfer ownership of, or other interests in, notes, you must do so through a direct participant or an indirect participant. DTC agrees with and represents to DTC participants that it will administer its book-entry system in accordance with its rules and by-laws and requirements of law. The SEC has on file a set of the rules applicable to DTC and its direct participants.

Purchases of notes under DTC’s system must be made by or through direct participants, who will receive a credit for the notes on DTC’s records. The ownership interest of each beneficial owner is in turn to be recorded on the records of direct participants and indirect participants. Beneficial owners will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct participants or indirect participants through which such beneficial owners entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in the notes, except in the event that use of the book-entry system for the notes is discontinued.

To facilitate subsequent transfers, all notes deposited by direct participants with DTC are registered in the name of DTC’s nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of notes with DTC and their registration in the name of Cede & Co. do

not effect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the notes. DTC’s records reflect only the identity of the direct participants to whose accounts such notes are credited, which may or may not be the beneficial owners. The participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Book-Entry Format. Under the book-entry format, the trustee will pay interest or principal payments to Cede & Co., as nominee of DTC. DTC will forward the payment to the direct participants, who will then forward the payment to the indirect participants or to you as the beneficial owner. You may experience some delay in receiving your payments under this system. Neither we, the trustee under the indenture nor any paying agent has any direct responsibility or liability for the payment of principal or interest on the notes to owners of beneficial interests in the notes.

DTC is required to make book-entry transfers on behalf of its direct participants and is required to receive and transmit payments of principal, premium, if any, and interest on the notes. Any direct participant or indirect participant with which you have an account is similarly required to make book-entry transfers and to receive and transmit payments with respect to the notes on your behalf. We, the underwriters and the trustee under the indenture have no responsibility for any aspect of the actions of DTC or any of its direct or indirect participants. We, the underwriters and the trustee under the indenture have no responsibility or liability for any aspect of the records kept by DTC or any of its direct or indirect participants relating to, or payments made on account of, beneficial ownership interests in the notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. We also do not supervise these systems in any way.

The trustee will not recognize you as a holder under the indenture, and you can only exercise the rights of a holder indirectly through DTC and its direct participants. DTC has advised us that it will only take action regarding a note if one or more of the direct participants to whom the note is credited directs DTC to take such action and only in respect of the portion of the aggregate principal amount of the notes as to which that participant or participants has or have given that direction. DTC can only act on behalf of its direct participants. Your ability to pledge notes to non-direct participants, and to take other actions, may be limited because you will not possess a physical certificate that represents your notes.

Neither DTC nor Cede & Co. (nor such other DTC nominee) will consent or vote with respect to the notes unless authorized by a direct participant in accordance with DTC’s procedures. Under its usual procedures, DTC will mail an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the notes are credited on the record date (identified in a listing attached to the omnibus proxy).

DTC has agreed to the foregoing procedures in order to facilitate transfers of the notes among its participants. However, DTC is under no obligation to perform or continue to perform those procedures, and may discontinue those procedures at any time.

The indenture contains certain limitations on the right of the trustee, should it become our creditor, to obtain payment of claims in certain cases, or to realize for its own account on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in certain other transactions. However, if it acquires any conflicting interest within the meaning of the Trust Indenture Act after a default has occurred and is continuing, it must eliminate the conflict within 90 days, apply to the SEC for permission to continue as trustee or resign.

If an Event of Default occurs and is not cured or waived, the trustee is required to exercise such of the rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as

a prudent man would exercise or use under the circumstances in the conduct of his own affairs. Subject to such provisions, the trustee will not be under any obligation to exercise any of its rights or powers under the indenture at the request of any of the holders of notes unless they have offered to the trustee reasonable security or indemnity against the costs, expenses and liabilities it may incur.

U.S. Bank National Association is the trustee under the indenture and has been appointed by Energy Transfer as registrar and paying agent with regard to the notes. The trustee’s address is 5555 San Felipe, Suite 1150, Houston, Texas 77056. The trustee and its affiliates maintain commercial banking and other relationships with Energy Transfer.

No Personal Liability of Directors, Officers, Employees, Limited Partners and Shareholders

The directors, officers, employees and limited partners of Energy Transfer and the General Partner will not have any personal liability for our obligations under the indenture or the notes. Each holder of notes, by accepting a note, waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the notes.

The indenture and the notes are governed by, and will be construed in accordance with, the laws of the State of New York.

“Attributable Indebtedness,” when used with respect to any Sale-Leaseback Transaction, means, as at the time of determination, the present value (discounted at the rate set forth or implicit in the terms of the lease included in such transaction) of the total obligations of the lessee for rental payments (other than amounts required to be paid on account of property taxes, maintenance, repairs, insurance, assessments, utilities, operating and labor costs and other items that do not constitute payments for property rights) during the remaining term of the lease included in such Sale-Leaseback Transaction (including any period for which such lease has been extended). In the case of any lease that is terminable by the lessee upon the payment of a penalty or other termination payment, such amount shall be the lesser of the amount determined assuming termination upon the first date such lease may be terminated (in which case the amount shall also include the amount of the penalty or termination payment, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated) or the amount determined assuming no such termination.

“Consolidated Net Tangible Assets” means, at any date of determination, the total amount of assets of Energy Transfer and its consolidated Subsidiaries after deducting therefrom:

(1) all current liabilities (excluding (A) any current liabilities that by their terms are extendable or renewable at the option of the obligor thereon to a time more than twelve months after the time as of which the amount thereof is being computed, and (B) current maturities of long-term debt); and

(2) the value (net of any applicable reserves) of all goodwill, trade names, trademarks, patents and other like intangible assets,

all as set forth, or on a pro forma basis would be set forth, on the consolidated balance sheet of Energy Transfer and its consolidated Subsidiaries for Energy Transfer’s most recently completed fiscal quarter for which financial statements have been filed with the SEC, prepared in accordance with generally accepted accounting principles.

“Credit Agreement” means the Second Amended and Restated Credit Agreement, dated as of October 27, 2011, among Energy Transfer, Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto, and as further amended, restated, refinanced, replaced or refunded from time to time.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and any successor statute.

“General Partner” means Energy Transfer Partners GP, L.P., a Delaware limited partnership, and its successors as general partner of Energy Transfer.

“Indebtedness” of any Person at any date means any obligation created or assumed by such Person for the repayment of borrowed money or any guaranty thereof.

(2) easements, rights-of-way, restrictions and other similar encumbrances incurred in the ordinary course of business and encumbrances consisting of zoning restrictions, easements, licenses, restrictions on the use of real property or minor imperfections in title thereto and which do not in the aggregate materially adversely affect the value of the properties encumbered thereby or materially impair their use in the operation of the business of Energy Transfer and its Subsidiaries;

(3) rights reserved to or vested by any provision of law in any municipality or public authority to control or regulate any of the properties of Energy Transfer or any Subsidiary or the use thereof or the rights and interests of Energy Transfer or any Subsidiary therein, in any manner under any and all laws;

(4) rights reserved to the grantors of any properties of Energy Transfer or any Subsidiary, and the restrictions, conditions, restrictive covenants and limitations, in respect thereto, pursuant to the terms, conditions and provisions of any rights-of-way agreements, contracts or other agreements therewith;

(5) any statutory or governmental lien or lien arising by operation of law, or any mechanics’, repairmen’s, materialmen’s, suppliers’, carriers’, landlords’, warehousemen’s or similar lien incurred in the ordinary course of business which is not more than sixty (60) days past due or which is being contested in good faith by appropriate proceedings and any undetermined lien which is incidental to construction, development, improvement or repair;

(6) any right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise, grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of, any property;

(7) liens for taxes and assessments which are (a) for the then current year, (b) not at the time delinquent, or (c) delinquent but the validity or amount of which is being contested at the time by Energy Transfer or any of its Subsidiaries in good faith by appropriate proceedings;

(10) any lien upon any property or assets of Energy Transfer or any Subsidiary in existence on the date of the initial issuance of the notes;

(11) any lien incurred in the ordinary course of business in connection with workmen’s compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations;

(12) liens in favor of any person to secure obligations under provisions of any letters of credit, bank guarantees, bonds or surety obligations required or requested by any governmental authority in connection with any contract or statute, provided that such obligations do not constitute Indebtedness; or any lien upon or deposits of any assets to secure performance of bids, trade contracts, leases or statutory obligations, and other obligations of a like nature incurred in the ordinary course of business;

(13) any lien upon any property or assets created at the time of acquisition of such property or assets by Energy Transfer or any of its Subsidiaries or within one year after such time to secure all or a

portion of the purchase price for such property or assets or debt incurred to finance such purchase price, whether such debt was incurred prior to, at the time of or within one year after the date of such acquisition;

(14) any lien upon any property or assets to secure all or part of the cost of construction, development, repair or improvements thereon or to secure Indebtedness incurred prior to, at the time of, or within one year after completion of such construction, development, repair or improvements or the commencement of full operations thereof (whichever is later), to provide funds for any such purpose;

(15) any lien upon any property or assets existing thereon at the time of the acquisition thereof by Energy Transfer or any of its Subsidiaries and any lien upon any property or assets of a Person existing thereon at the time such Person becomes a Subsidiary of Energy Transfer by acquisition, merger or otherwise; provided that, in each case, such lien only encumbers the property or assets so acquired or owned by such Person at the time such Person becomes a Subsidiary;

(16) liens imposed by law or order as a result of any proceeding before any court or regulatory body that is being contested in good faith, and liens which secure a judgment or other court-ordered award or settlement as to which Energy Transfer or the applicable Subsidiary has not exhausted its appellate rights;

(17) any extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refunding or replacements) of liens, in whole or in part, referred to in clauses (1) through (16) above; provided, however, that any such extension, renewal, refinancing, refunding or replacement lien shall be limited to the property or assets covered by the lien extended, renewed, refinanced, refunded or replaced and that the obligations secured by any such extension, renewal, refinancing, refunding or replacement lien shall be in an amount not greater than the amount of the obligations secured by the lien extended, renewed, refinanced, refunded or replaced and any expenses of Energy Transfer or its Subsidiaries (including any premium) incurred in connection with such extension, renewal, refinancing, refunding or replacement; or

(18) any lien resulting from the deposit of moneys or evidence of indebtedness in trust for the purpose of defeasing Indebtedness of Energy Transfer or any of its Subsidiaries.

“Person” means any individual, corporation, partnership, limited liability company, joint venture, incorporated or unincorporated association, joint-stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“Principal Property” means, whether owned or leased on the date of the initial issuance of the notes or thereafter acquired:

(1) any pipeline assets of Energy Transfer or any of its Subsidiaries, including any related facilities employed in the gathering, transportation, distribution, storage or marketing of natural gas, refined petroleum products, natural gas liquids and petrochemicals, that are located in the United States of America or any territory or political subdivision thereof; and

(2) any processing, compression, treating, blending or manufacturing plant or terminal owned or leased by Energy Transfer or any of its Subsidiaries that is located in the United States or any territory or political subdivision thereof, except in the case of either of the preceding clause (1) or this clause (2):

(a) any such assets consisting of inventories, furniture, office fixtures and equipment (including data processing equipment), vehicles and equipment used on, or useful with, vehicles; and

(b) any such assets which, in the opinion of the board of directors of the General Partner are not material in relation to the activities of Energy Transfer and its Subsidiaries taken as a whole.

“Restricted Subsidiary” means any Subsidiary owning or leasing, directly or indirectly through ownership in another Subsidiary, any Principal Property.

“Subsidiary” means, with respect to any Person, any corporation, association or business entity of which more than 50% of the total voting power of the equity interests entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof or any partnership of which more than 50% of the partners’ equity interests (considering all partners’ equity interests as a single class) is, in each case, at the time owned or controlled, directly or indirectly, by such Person or one or more Subsidiaries of such Person or a combination thereof.

“Subsidiary Guarantor” means each Subsidiary of Energy Transfer that guarantees the notes pursuant to the terms of the indenture but only so long as such Subsidiary is a guarantor with respect to the notes on the terms provided for in the indenture.

The following discussion summarizes certain U.S. federal income tax considerations that may be relevant to the acquisition, ownership and disposition of the notes, but does not purport to be a complete analysis of all potential tax effects. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), applicable Treasury Regulations promulgated and proposed thereunder, Internal Revenue Service (“IRS”) rulings and pronouncements, and judicial decisions, all as of the date hereof and all of which are subject to change at any time. Any such change may be applied retroactively in a manner that could adversely affect a holder of the notes. We cannot assure you that the IRS will not challenge one or more of the tax consequences described herein, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal tax consequences of acquiring, holding or disposing of the notes.

This discussion is limited to persons purchasing the notes in this offering for cash at their “issue price” (the first price at which a substantial amount of the issue of notes is sold to purchasers other than bond houses, brokers, or similar persons or organizations acting in the capacity of underwriters, placement agents, or wholesalers) and holding the notes as “capital assets” within the meaning of Section 1221 of the Code (generally, property held for investment). Moreover, the effects of other U.S. federal tax laws (such as estate and gift tax laws or the Medicare tax on investment income) and any applicable state, local or foreign tax laws are not discussed. In addition, this discussion does not address all of the U.S. federal income tax considerations that may be relevant to a particular holder in light of the holder’s particular circumstances, or to holders subject to special rules, including, without limitation:

If a partnership or other entity taxed as a partnership for U.S. federal income tax purposes holds notes, the tax treatment of the partners in the partnership generally will depend on the status of the particular partner in question and the activities of the partnership. Such partners should consult their tax advisors as to the specific tax consequences to them of acquiring, holding and disposing of the notes.

Investors considering the purchase of notes should consult their tax advisors regarding the application of the U.S. federal income tax laws to their particular situations as well as any tax consequences of the purchase, ownership or disposition of the notes under U.S. federal estate or gift tax laws, and the applicability and effect of state, local or foreign tax laws and tax treaties.

The following is a summary of certain U.S. federal income tax considerations that will apply to you if you are a “U.S. holder” of the notes. The term “U.S. holder” means a beneficial owner of a note who or which is for U.S. federal income tax purposes:

Stated interest paid or accrued on the notes generally will be taxable to you as ordinary income at the time such interest is received or accrued, in accordance with your regular method of accounting for U.S. federal income tax purposes.

You will recognize taxable gain or loss on the sale, exchange, redemption, retirement or other taxable disposition of a note equal to the difference, if any, between:

Your adjusted tax basis in a note generally will equal the amount that you paid for the note. Any gain or loss will be capital gain or loss and will be long-term capital gain or loss if at the time of the sale or other taxable disposition you have held the note for more than one year. Otherwise, such gain or loss will be short-term capital gain or loss. Long-term capital gains recognized by certain non-corporate U.S. holders, including individuals, generally will be subject to a reduced rate of tax. The deductibility of capital losses is subject to limitations.

You may be subject to information reporting on interest on the notes and on the proceeds received upon the sale or other disposition (including a retirement or redemption) of the notes, and backup withholding also may apply to payments of such amounts. Certain U.S. holders are generally not subject to information reporting or backup withholding. You will be subject to backup withholding if you are not otherwise exempt and you:

U.S. holders should consult their tax advisors regarding their qualification for an exemption from backup withholding and the procedures for obtaining such an exemption, if applicable. Backup withholding

is not an additional tax, and you may use amounts withheld as a credit against your U.S. federal income tax liability, if any, or you may claim a refund if you timely provide certain information to the IRS.

The following is a summary of certain U.S. federal income tax considerations that will apply to you if you are a “non-U.S. holder” of the notes. A “non-U.S. holder” is a beneficial owner of a note that is an individual, corporation, estate or trust that is not a U.S. holder.

Interest paid on a note to you that is not effectively connected with your conduct of a U.S. trade or business generally will not be subject to U.S. federal withholding tax of 30% (or, if applicable, a lower treaty rate) provided that:

Even if the above conditions are not met, you may be entitled to a reduction in or an exemption from withholding tax on interest if you provide the applicable withholding agent with a properly executed (1) IRS Form W-8BEN claiming an exemption from or reduction of the withholding tax under the benefit of a tax treaty between the United States and your country of residence, or (2) IRS Form W-8ECI stating that interest paid on a note is not subject to withholding tax because it is effectively connected with your conduct of a trade or business in the United States.

If interest paid to you is effectively connected with your conduct of a U.S. trade or business (and, if required by an applicable income tax treaty, you also maintain a U.S. permanent establishment to which such interest is attributable), then, although exempt from U.S. federal withholding tax (provided you provide the appropriate certification), you generally will be subject to U.S. federal income tax on such interest in the same manner as if you were a U.S. holder. In addition, if you are a foreign corporation, such interest may be subject to a branch profits tax at a rate of 30% or lower applicable treaty rate.

Any gain realized by you on the sale, exchange, retirement, redemption or other disposition of a note generally will not be subject to U.S. federal income tax (other than any amount allocable to accrued and unpaid interest, which generally will be taxable as interest and may be subject to the rules discussed above in “Consequences to Non-U.S. Holder—Payments of Interest) unless:

If you recognize gain described in the first bullet point above, you will be required to pay U.S. federal income tax on the net gain derived from the sale generally in the same manner as if you were a U.S. holder, and if you are a foreign corporation, you may also be required to pay an additional branch profits tax at a 30% rate (or a lower rate if so specified by an applicable income tax treaty). If you are a non-U.S. holder described in the second bullet point above, you will be subject to U.S. federal income tax at a rate of 30% (or, if applicable, a lower treaty rate) on the gain derived from the sale or other disposition of the note, which may be offset by certain U.S. source capital losses, even though you are not considered a resident of the United States.

You should consult your tax advisor regarding potentially applicable income tax treaties that may provide for different rules.

You generally will not be subject to backup withholding and information reporting with respect to payments of interest on the notes if you have provided the statement described above under “—Consequences to Non-U.S. Holders—Payments of Interest” and the applicable withholding agent does not have actual knowledge or reason to know that you are a “U.S. person,” within the meaning of the Code. In addition, you will not be subject to backup withholding or information reporting with respect to the proceeds of the sale or other disposition of a note (including a retirement or redemption of a note) within the United States or conducted through certain U.S.-related brokers, if the payor receives the statement described above and does not have actual knowledge or reason to know that you are a U.S. person or you otherwise establish an exemption. However, we may be required to report annually to the IRS and to you the amount of, and the tax withheld with respect to, any interest paid to you, regardless of whether any tax was actually withheld. Copies of these information returns may also be made available under the provisions of a specific treaty or agreement to the tax authorities of the country in which you reside.

You generally will be entitled to credit any amounts withheld under the backup withholding rules against your U.S. federal income tax liability, if any, or you may claim a refund provided that the required information is furnished to the IRS in a timely manner.

Withholding taxes may be imposed under the Foreign Account Tax Compliance Act (“FATCA”) to certain types of payments made to “foreign financial institutions” (as defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest on, or gross proceeds from the sale or other disposition of the notes paid to a “foreign financial institution” (as defined in the Code) or a “non-financial foreign entity” (as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities (as defined in the Code), annually report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders.

Under proposed Treasury Regulations, debt securities that were outstanding on or before January 1, 2013 are grandfathered from the application of the withholding rules under FATCA. For those that are not grandfathered (which would include the notes), the proposed Treasury Regulations and subsequent IRS guidance indicate that withholding under FATCA will apply to payments of interest on debt securities made on or after January 1, 2014 and to payments of gross proceeds from the sale or other disposition of debt securities on or after January 1, 2017.

The proposed Treasury Regulations described above will not be effective until they are issued in their final form, and as a result, it is not certain that the provisions under the proposed Treasury Regulations would become effective in their current form. Prospective investors should consult their tax advisors regarding these withholding provisions.

The preceding discussion of certain U.S. federal income tax considerations is for general information only and is not tax advice. Each prospective investor should consult their tax advisor regarding the particular federal, state, local and foreign tax consequences of purchasing, holding, and disposing of our notes, including the consequences of any proposed change in applicable laws.

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement by and among us and the underwriters named below, for whom Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC are acting as representatives, we have agreed to sell to each of the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the principal amount of the notes indicated in the following table.

Under the terms and conditions of the underwriting agreement, if the underwriters take any of the notes, then they are obligated to take and pay for all the notes.

The notes are new issues of securities with no established trading market. We do not intend to apply for the listing of the notes on any securities exchange or for the quotation of the notes on any automated dealer quotation system. The underwriters have advised us that they intend to make a market for each series of the notes, but they have no obligation to do so and may discontinue market-making at any time without providing any notice. No assurance can be given as to the liquidity of any trading markets for the notes.

Notes sold by the underwriters to the public will initially be offered at the public offering prices set forth on the cover page of this prospectus supplement. Any notes sold by the underwriters to securities dealers may be sold at a discount from the public offering price of up to % of the principal amount of the 2023 notes and % of the principal amount of the 2043 notes. The underwriters may allow, and any such dealer may reallow, a concession not in excess of % of the principal amount of the 2023 notes and % of the principal amount of the 2043 notes to certain other dealers. After the initial offering of the notes to the public, the underwriters may change the offering prices and other selling terms.

The following table summarizes the compensation to be paid by us to the underwriters:

We estimate that the total expenses of this offering to be paid by us, excluding underwriting discounts, will be approximately $0.5 million.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that the underwriters may be required to make in respect of any such liabilities.

In connection with the offering, the underwriters may purchase and sell notes in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of notes than it is required to purchase in the offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market prices of the notes while the offering is in progress. These activities by the underwriters may stabilize, maintain or otherwise affect the market prices of the notes. As a result, the prices of the notes may be higher than the prices that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. These transactions may be effected in the over-the-counter market or otherwise.

We expect delivery of the notes will be made against payment therefor on or about , 2013, which will be the fifth business day following the date of pricing of the notes (such settlement being referred to as “T+5”). Under Rule 15c6-1 of the Securities Exchange Act of 1934, as amended, trades in the secondary market generally are required to settle in three business days unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade the notes on the date of pricing of the notes or the next succeeding business day will be required, by virtue of the fact that the notes initially will settle in T+5, to specify an alternate settlement cycle at the time of any such trade to prevent failed settlement and should consult their own advisers.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us or our affiliates. They have received, or may in the future receive, customary fees and commissions for these transactions. In particular, affiliates of Merrill Lynch, Pierce, Fenner & Smith Incorporated, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC are lenders and agents under our revolving credit facility. These affiliates will receive their respective share of the repayment by us of amounts outstanding under our revolving credit facility with the net proceeds of this offering. In addition, Wells Fargo Securities, LLC has been engaged by Laclede to act as its financial advisor in connection with the Southern Union local distribution company dispositions, for which it will receive a customary fee if the transaction is consummated. Additionally, Wells Fargo Securities, LLC and Wells Fargo Bank, National Association entered into a commitment letter with Laclede to provide a bridge term loan credit facility in an aggregate principal amount of up to $1.020 billion to fund the transaction.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and instruments of ours or our affiliates. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities, including potentially the notes offered hereby. Any such short positions could adversely affect future trading prices of the notes offered hereby. The underwriters and their respective affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

The validity of the notes offered in this prospectus supplement will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting of Energy Transfer Partners, L.P. appearing in Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2011 and incorporated by reference in this prospectus supplement, have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing in giving said reports.

The consolidated financial statements of Southern Union Company and its subsidiaries at December 31, 2011 and 2010, and for each of the three years ended December 31, 2011 incorporated in this prospectus supplement by reference to Energy Transfer Partners, L.P.’s Current Report on Form 8-K filed with the SEC on June 25, 2012, have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of Citrus Corp. and its subsidiaries as of December 31, 2011 and 2010, and for each of the three years ended December 31, 2011, incorporated by reference in this prospectus supplement by reference to Energy Transfer Partners, L.P.’s Current Report on Form 8-K filed with the SEC on June 6, 2012, have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of Sunoco, Inc. and subsidiaries as of December 31, 2011 and 2010, and for each of the three years in the period ended December 31, 2011, appearing in Sunoco, Inc.’s Current Report (Form 8-K) dated June 22, 2012, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon, included therein, and incorporated herein by reference. Such consolidated financial statements of Sunoco, Inc. and subsidiaries’ as of December 31, 2011 are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

We file annual, quarterly and other reports and other information with the Securities and Exchange Commission, or 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 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.

We may offer and sell the common units representing limited partner interests and debt securities of Energy Transfer Partners, L.P. as 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.

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, or the SEC, 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, two interstate pipelines, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Arkansas, Mississippi, West Virginia, Colorado and Utah, and three natural gas storage facilities located in Texas. These assets include more than 17,500 miles of pipeline in service and a 50% interest in a joint venture that has approximately 185 miles of interstate pipeline in service. Our intrastate and interstate pipeline systems transport natural gas from several significant natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in north Texas, the Bossier Sands in east Texas, the Permian Basin in west Texas and New Mexico, the San Juan Basin in New Mexico, the Fayetteville Shale in Arkansas, the Haynesville Shale in north Louisiana, the Eagle Ford Shale in south and central Texas, and other producing areas in Texas and Louisiana. Our gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. 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 prospectus 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.

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

The amount of cash we can distribute to holders of 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, unitholders 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 our 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 public market could reduce the market price of unitholders’ limited partner interests.

As of December 31, 2010, Energy Transfer Equity, L.P., or ETE, owned 50,226,967 ETP common units. ETE also 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.

In August 2009, we filed a registration statement to register 12,000,000 ETP common units held by ETE, which allows ETE to offer and sell these ETP common units from time to time in one or more public offerings, direct placements or by other means.

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

As of September 30, 2010, we had approximately $6.0 billion of consolidated debt, excluding the credit facilities of our joint ventures and of Midcontinent Express Pipeline, LLC, which we guarantee in part. Our level of indebtedness affects our operations in several ways, including, among other things:

Construction of new pipeline 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 growth capital expenditures, including any new pipeline construction projects we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. 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.

As of September 30, 2010, we had approximately $6.0 billion of total debt. A significant increase in our indebtedness that is proportionately greater than our issuances of equity could negatively impact our credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows.

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

In addition to our exposure to commodity prices, we have exposure to increases in interest rates. As of September 30, 2010, we had no variable rate debt outstanding. However, we had fixed-to-floating interest rate swaps outstanding as of September 30, 2010 with total notional amounts of $400.0 million that are not designated as hedges for accounting purposes. To the extent that we have variable rate debt or interest rate swaps outstanding, our results of operations, cash flows and financial condition could be adversely affected by 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, and of ETE as the indirect owner of our general partner, may be factors in credit evaluations of us as a publicly traded limited partnership due to the significant influence of our general partner and ETE over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.

ETE has significant indebtedness outstanding and is dependent principally on the cash distributions from its general and limited partner equity interests in us and in Regency Energy Partners LP, or Regency, to

service such indebtedness. Any distributions by us to ETE 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, Energy Transfer Partners GP, L.P., or ETP GP, and Energy Transfer Partners, L.L.C., or ETP LLC, from the entities that control ETP GP (ETE and its general partner), 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 riskier 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. 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 our unitholders, the directors of our general partner and its general partner 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 December 31, 2010, ETE and its affiliates held approximately 26% of our outstanding units, with an additional approximate 1% of our outstanding units held by our officers and directors. Consequently, it could be difficult to remove our general partner without the consent of the general partner and our related parties.

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.

Our general partner may transfer its general partner interest to a third party without the consent of the unitholders. Furthermore, the general partner of our general partner may transfer its general partner interest in our general partner to a third party without the consent of the unitholders. Any new owner of the general partner or the general partner 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 other than that of our operating subsidiaries. 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 to our general partner may be substantial and may reduce our ability to pay the distributions to unitholders.

Prior to making any distributions to our unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by 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.

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.

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 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 that may permit our general partner to favor its own interests to the detriment of unitholders.

ETE owns our general partner and as a result controls us. ETE also owns the general partner of Regency, a publicly traded partnership with which we compete in the natural gas gathering, processing and transportation business. The directors and officers of our general partner and its affiliates have fiduciary duties to manage our general partner in a manner that is beneficial to ETE, the sole owner of our general partner. At the same time, our general partner has fiduciary duties to manage us in a manner that is beneficial to our unitholders. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to ETE as its sole owner. As a result of these conflicts of interest, our general partner may favor its own interest or those of ETE, Regency or their owners or affiliates over the interest of our unitholders.

In addition, certain conflicts may arise as a result of our pursuing acquisitions or development opportunities that may also be advantageous to Regency. If we are limited in our ability to pursue such opportunities, we may not realize any or all of the commercial value of such opportunities. In addition, if Regency is allowed access to our information concerning any such opportunity and Regency uses this information to pursue the opportunity to our detriment, we may not realize any of the commercial value of this opportunity. In either of these situations, our business, results of operations and the amount of our distributions to our unitholders may be adversely affected. Although we, ETE and Regency have adopted a policy to address these conflicts and to limit the commercially sensitive information that we furnish to ETE, Regency and their affiliates, we cannot assure you that such conflicts will not occur or that this policy will be effective in all circumstances to protect our commercially sensitive information or to realize the commercial value of our business opportunities.

Except as provided in our partnership agreement, affiliates and related parties 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 26, 2010, our general partner acquired all of the general partner interests in Regency, which competes with us with respect to our natural gas operations. Additionally, two directors of Regency GP LLC currently serve as directors of LE GP, LLC, the general partner of ETE.

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 profitability of certain activities in 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 is exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the North Texas System, Southeast Texas System and HPL System, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

For a portion of the natural gas gathered and processed at the North Texas System and Southeast Texas System, 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 year ended December 31, 2009, the NYMEX settlement price for the prompt month contract ranged from a high of $6.14 per MMBtu to a low of $2.84 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during our year ended December 31, 2009 ranged from a high of approximately $1.17 per gallon to a low of approximately $0.57 per gallon.

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, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas or may result in decisions by end-users of natural gas 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 risk management mechanisms and by our marketing and/or system optimization activities. 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 derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to 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 and natural gas transportation services.

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.

Our subsidiary, Transwestern Pipeline Company, LLC, or Transwestern, derives a significant portion of its revenue from charging its customers for reservation of capacity, which revenues 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. If the reserves available through the supply basins connected to Transwestern’s systems decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission or a decrease in demand for natural gas transportation on the Transwestern system over the long run.

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 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 give assurance 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, both of which would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.

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

At September 30, 2010, our consolidated balance sheet reflected $772.8 million of goodwill and $261.4 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair 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’ capital and balance sheet leverage as measured by debt to total capitalization.

As of December 31, 2010, our goodwill impairment tests are not yet completed for certain reporting units with an aggregate goodwill balance of approximately $100 million.

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 will depend in part 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 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, unitholders 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 are currently involved in constructing several new pipelines. Our results of operations and 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, at all, or at the budgeted cost. We currently have several expansion and new build projects planned or underway. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors has resulted in, and may continue to result in, increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following the completion of a particular project. 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. In addition, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in this area to utilize the newly constructed pipelines. In this regard, we may construct facilities to capture anticipated future growth in natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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 year ended December 31, 2009, EnCana Oil and Gas (USA), Inc., XTO Energy Inc., or XTO, SandRidge Energy Inc., and EnerVest Operating, LLC, supplied us with approximately 70% of the Southeast Texas System’s natural gas supply. In June 2010, Exxon Mobil Corporation, or ExxonMobil, completed its acquisition of XTO. For our year ended December 31, 2009, Chesapeake Energy Marketing, Inc., XTO, EOG Resources, Inc., and EnCana Oil and Gas (USA), Inc., supplied us with approximately 84% 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 through our pipelines.

We have nine- and ten-year fee-based transportation contracts with XTO that terminate in 2013 and 2017, respectively, pursuant to which XTO has committed to transport certain minimum volumes of natural gas on pipelines in our ET Fuel System. The acquisition of XTO by ExxonMobil has not resulted in any changes to these commitments. We also have an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., or 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 that terminate in 2012 with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO 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.

The major shippers on our intrastate transportation pipelines include XTO, EOG Resources, Inc., Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. and Quicksilver Resources, Inc. These shippers have long-term contracts that have remaining terms ranging from 1 to 10 years.

Transwestern generates the majority of its revenues from long-term and short-term firm transportation contracts with natural gas producers, local distribution companies and end-users. During 2009, ConocoPhillips, Salt River Project and BP Energy Company collectively accounted for 32% of Transwestern’s total revenues.

The failure of the major shippers on our intrastate and interstate transportation pipelines 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.

With respect to our interstate transportation operations, Fayetteville Express Pipeline LLC, an entity in which we own a 50% interest, has secured binding 10-year commitments from a small number of major shippers for approximately 1.85 Bcf/d of firm transportation service on the 2.0 Bcf/d Fayetteville Express pipeline. In connection with our Tiger pipeline, we have an agreement with Chesapeake Energy Marketing, Inc. that provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. We also have agreements with EnCana Marketing (USA), Inc. and other shippers that provide for 10-year commitments for firm transportation capacity on the Tiger pipeline, bringing the initial design capacity to 2.0 Bcf/d in the aggregate. In February 2010, we announced that we had entered into a 10-year commitment for an additional 400 MMcf/d.

The failure of any of our key 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 our existing contracts.

Federal, state or local regulatory measures could adversely affect the business and operations of our midstream and intrastate assets.

Our midstream and intrastate transportation and storage operations are generally exempt from regulation by the Federal Energy Regulatory Commission, or the FERC, under the Natural Gas Act, or the NGA, 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 East Texas pipeline, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or the NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the 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, and failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

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

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

Our intrastate transportation and storage operations are subject to state regulation in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado, the states in which we operate these types of natural gas facilities. Our intrastate transportation operations located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or the 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 midstream and intrastate transportation operations are also subject to ratable take and common purchaser statutes in Texas, New Mexico, Arizona, Louisiana, Utah and Colorado. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting 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. Because the natural gas storage facilities of the ET Fuel System and HPL System are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRRC-jurisdictional storage facilities, such as

facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures.

Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.

The states in which 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 U.S. Department of Transportation, or the DOT, have passed or are considering heightened pipeline safety requirements.

Failure to comply with applicable laws and regulations could result in the imposition of administrative, civil and criminal remedies.

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

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

Transwestern made a general rate case filing under Section 4 of the NGA in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file a new general rate case until October 2011. However, shippers (other than shippers that have agreed, as parties to the Stipulation and Agreement, not to challenge Transwestern’s tariff rates through the remaining term of the settlement) have the statutory ability to challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint.

Most of the rates to be paid by the initial shippers on our newly constructed interstate pipelines are established pursuant to long-term, negotiated rate transportation agreements. Other prospective shippers on our newly constructed interstate pipelines that elect not to pay a negotiated rate for service may opt instead to pay a cost-based recourse rate established by the FERC as part of our newly constructed interstate pipelines’ certificates of public convenience and necessity. Negotiated rate agreements generally provide a degree of certainty to the pipeline and shipper as to a fixed rate during the term of the relevant transportation agreement, but such agreements can limit the pipeline’s future ability to collect costs associated with construction and operation of the pipeline that might be higher than anticipated at the time the negotiated rate agreement was entered. On December 17, 2009, the FERC issued an order granting authorization to construct, own and operate the Fayetteville Express pipeline, and on April 7, 2010, the FERC issued an order granting authorization to construct, own and operate the Tiger pipeline. On June 17, 2010, we filed an application for authorization to construct, own and operate the Tiger pipeline expansion project to add 400 MMcf/d of capacity to the Tiger pipeline. The FERC has not yet determined whether the Tiger pipeline expansion project should be granted the requested authority. We cannot predict if, or when and with what conditions, FERC authorization for the Tiger pipeline expansion project will be granted.

Any successful challenge to the rates of our interstate natural gas companies, whether brought by complaint, protest or investigation, could reduce our revenues associated with providing transportation services on a prospective basis. We cannot guarantee that our interstate pipelines will be able to recover all of their costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before the 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 the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, we thus remain eligible to include an income tax allowance in the tariff rates we charge for interstate natural gas transportation. The application of that policy remains subject to future refinement or change by the FERC. With regard to rates charged and collected by Transwestern, the allowance for income taxes as a cost-of-service element in our tariff rates is generally not subject to challenge prior to the expiration of our settlement agreement in 2011.

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

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

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

We must on occasion rely upon rulings by the FERC or other governmental authorities to carry out certain of our business plans. For example, in order to carry out our plan to construct the Fayetteville Express and Tiger pipelines we were required to, among other things, file and support before the FERC NGA Section 7(c) applications for certificates of public convenience and necessity to build, own and operate such facilities. Although the FERC has authorized the construction and operation of the Fayetteville Express and Tiger pipelines, the FERC has not yet ruled upon the Tiger pipeline expansion project application, and we cannot guarantee that FERC will authorize construction and operation of that project or any future interstate natural gas

transportation project we might propose. Moreover, there is no guarantee that, if granted, certificate authority for the Tiger expansion project, or any future interstate projects, will be granted in a timely manner or will be free from potentially burdensome conditions.

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, the 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. The FERC possesses similar authority under the NGPA.

Finally, we cannot give any assurance regarding the likely future regulations under which we will operate our interstate pipelines 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 and propane operations are subject to stringent federal, state, and local laws and regulations that seek to protect human health and the environment, including those governing the emission or discharge of materials into the environment. 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, or the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant 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 of the underlying risk inherent to our operations. Certain environmental laws and regulations can provide for joint and several strict liabilities for cleanup to address discharges or releases of petroleum hydrocarbons or other materials or wastes at sites to which we may have sent wastes or on, under or from our properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by our predecessors. 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, personal injury or property damage. The total accrued future estimated cost of remediation activities relating to our Transwestern pipeline operations expected to continue through 2018 was $8.3 million as of September 30, 2010.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For example, the EPA in 2008 lowered the federal ozone standard from 0.08 parts per million to 0.075 parts per million, requiring the environmental agencies in states with areas that do not currently meet this standard to adopt new rules between to further reduce NOx and other ozone precursor emissions. The EPA recently proposed to lower the standard even further, to somewhere between 0.060 and 0.070 ppm. We have previously been able to satisfy the more stringent NOx emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no guarantee that the changes we may have to make in the future to meet the new ozone standard or other evolving standards will not require us to incur costs that could be material to our operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and other hydrocarbon products that we transport, store or otherwise handle in connection with our transportation, storage, and midstream services.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA recently adopted two sets of regulations addressing greenhouse gas emissions under the Clean Air Act. The first limits emissions of greenhouse gases from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle greenhouse gas emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration, or PSD, and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology” standards for greenhouse gases that have yet to be developed. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the natural gas and other hydrocarbon products that we transport, store, process, or otherwise handle in connection with our services.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 8, 2010, the EPA revised its greenhouse gas reporting rule to expressly include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. Reporting of greenhouse gas emissions from such facilities, including many of our facilities, will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In June 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or ACESA, which would establish an economy-wide cap on emissions of greenhouse gases in the United States and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Legislation to reduce emissions of greenhouse gases by comparable amounts is currently pending in the United States Senate, and more than one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our own operations, and it could also adversely affect demand for our transportation, storage, and midstream services.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our propane and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

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.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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

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 extensions of existing and any 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. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively.

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 our processing plants when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on the Oasis pipeline and ET Fuel System. In some circumstances, such as when 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 the year ended December 31, 2009, approximately 26% of our sales of natural gas was 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 may depend 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 pipeline operations are subject to regulation by the DOT under the Pipeline and Hazardous Materials Safety Administration, or PHMSA, pursuant to which the PHMSA has established requirements 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.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. 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 will result in capital costs of $16.8 million and operating and maintenance costs of $15.0 million over the course of the next year. For the year ended December 31, 2010, capital costs of approximately $13.8 million and operating and maintenance costs of approximately $15.9 million were incurred for pipeline integrity testing, based on actual costs incurred through September 30, 2010 and estimated costs for the remainder of 2010. For the years ended December 31, 2009 and 2008, $31.4 million and $23.3 million, respectively, of capital costs and $18.5 million and $13.1 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause 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.

Changes in other forms of health and safety regulations are also being considered. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the

U.S. Senate. Similar legislation is likely to be considered in the next session of Congress. The DOT has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the PHMSA’s announced intention to strengthen its rules. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

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 unseasonably cold or hot periods or dry weather conditions that impact agricultural operations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail 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.

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 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 2009, we purchased approximately 50.3%, 14.3% and 15.1% of our propane from Enterprise Products Operating L.P., Targa Liquids Marketing and Trade and M.P. Oils, Ltd., respectively. Titan purchases the majority of its propane from Enterprise pursuant to an agreement that was extended until March 2015 and contains an option to renew for an additional year. 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.

In addition to reading the following risk factors, please read “Material Federal 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 for federal income tax purposes 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, with respect to our classification as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. If we are so treated, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state income taxes as well. 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. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Specifically, federal income tax legislation has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. Several states currently impose entity-level taxes on partnerships, including us. Further, because of widespread state budget deficits and other reasons, several additional states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If any additional states were to impose a tax upon us as an entity, our cash available for

distribution would be reduced. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

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.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of 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 may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on 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.

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.

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 (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes, generally at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal and state income tax returns and generally pay United States federal and state income tax on their share of our taxable income.

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.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Section 743(b) of the Internal Revenue Code. 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. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

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, the unitholder 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, the unitholder 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. 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.

We will be considered technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders which would require us to file two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year, and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes. We would be treated as a new partnership for tax purposes, and would be required to make new tax elections and could be subject to penalties if we were unable to determine in a timely manner that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Considerations—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

In November 2010, Enterprise GP Holdings L.P., which held approximately 17.6% of the outstanding common units of ETE and an approximate 40.6% interest in ETE’s general partner, merged into Enterprise Products Partners L.P. For federal income tax purposes, this transaction will be treated as a change of ownership of the interests in ETE and its general partner formerly owned by Enterprise GP Holdings L.P. The completion of this merger increased the likelihood that a termination of our partnership for federal income tax purposes may have occurred at that time or may occur at any time during the twelve-month period following the consummation of the transaction, resulting in a closing of our taxable year, as discussed above.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they 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 conduct 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. We 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. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. 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 our common units.

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 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.

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:

As of December 31, 2010, there were approximately 265,000 separate 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 in our Second Amended and Restated Agreement of Limited Partnership.

As of December 31, 2010, we had 193,212,590 common units outstanding, of which 142,985,623 were held by the public, including approximately 575,000 common units held by our officers and directors, and 50,226,967 common units held by ETE. Our common units are listed for trading on the NYSE under the symbol “ETP.” The common units are entitled to distributions of available cash as described below under “Cash Distribution Policy.”

There are currently 8,853,832 Class E units outstanding, all of which were issued in conjunction with our purchase of the capital stock of Heritage Holdings Inc., or Heritage Holdings, in January 2004, and are currently owned by our subsidiary 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 as long as such units remain outstanding.

As of December 31, 2010, our general partner owned an approximate 1.8% general partner interest in us and the holders of common units and Class E units collectively owned an approximate 98.2% limited partner interest in us.

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 has the right to make additional capital contributions to the extent necessary to maintain its then-existing general partner interest in us. In the event that our general partner does not make its proportionate share of capital contributions to us based on its then-current general partner interest percentage, its general partner percentage will be proportionately reduced. 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.

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.

Our general partner manages and directs all of our activities. The activities of our general partner are managed and directed by its general partner, ETP LLC. Our officers and directors are officers and directors of ETP LLC. ETE, as the sole member of ETP LLC, is entitled under the limited liability company agreement of ETP LLC to appoint all of the directors of ETP LLC. Our unitholders do not have the ability to nominate directors or vote in the election of the directors of ETP LLC.

Amendments to our partnership agreement may be proposed only by or with the consent of 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:

Our general partner may withdraw as general partner by giving 90 days’ written notice to the unitholders, and that withdrawal will not constitute a violation of our partnership agreement. 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 66²/₃% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist, 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 if, among other things, the transferee assumes the rights and duties of our general partner, furnishes an opinion of counsel regarding limited liability and tax matters and agrees to purchase all (or the appropriate portion thereof, if applicable) of our general partner’s general partner interest in us and any of our subsidiaries. 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.

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.

If at any time less than 20% of the total limited partner interests 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.

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 and, with respect to any criminal proceeding, had no reasonable cause to believe the conduct was unlawful. 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.

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.

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

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 common unit as the absolute owner for all purposes, except as otherwise required by law or NYSE regulations.

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.

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, or 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 to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement, constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of 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 45 states: Alabama, Arizona, Arkansas, California, Colorado, Connecticut, Delaware, Florida, Georgia, Idaho, Illinois, Indiana, Kansas, 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, Rhode Island, South Carolina, South Dakota, Tennessee, Texas, Utah, Vermont, Virginia, Wisconsin, 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.

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. If authorized by our general partner, 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.

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 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

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

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.

Following is a description of the relative rights and preferences of holders of our common units in and to cash distributions. Upon the issuance of any additional common units, the general partner may make, but is not obligated to make, capital contributions to maintain its then current general partner interest. In the event the general partner elects not to make such capital contribution, its general partner interest will be diluted accordingly. As of December 31, 2010, our general partner owned an approximate 1.8% general partner interest in us.

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:

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 represent the contractual right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution has been paid. Please read “—Distributions of Available Cash from Operating Surplus” below. The general partner owns all of the incentive distribution rights.

The terms of our partnership agreement require that we make cash distributions with respect to each calendar quarter within 45 days following the end of each calendar quarter. 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.

The terms of our partnership agreement require that we make cash distributions with respect to each calendar quarter within 45 days following the end of each calendar quarter. 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 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.

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 Adjustment 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 the indenture, dated January 18, 2005, among Energy Transfer Partners, L.P., as issuer, the subsidiary guarantors party thereto and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee. 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 of 1939, as amended, or 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.

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 the guarantee of 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, the guarantee of a Subsidiary Guarantor will be unconditionally released and discharged:

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 governs the indenture and will govern 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 Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury 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 subsidiaries.

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. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. 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.

No ruling has been or will be requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. 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.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP 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” and “—Uniformity of Units”).

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. We estimate that less than 6% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

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 our operating subsidiaries for federal income tax purposes. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its Treasury Regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and each of our operating subsidiaries will, except as otherwise provided, be disregarded as an entity separate from us or will be treated as a partnership for federal income tax purposes. In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

We believe that these representations have been true in the past and expect that these representations will be true in the future.

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 and 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 Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

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:

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, Latham & Watkins LLP’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. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Energy Transfer Partners, L.P., for federal income tax purposes.

Flow-Through of Taxable Income. Subject to the discussion below under “—Entity-Level Collections,” 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. This deemed distribution may constitute a non-pro rata distribution. 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 limitations must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable 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 a unitholder’s 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 (if applicable) 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 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 the 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, or in conjunction with, such other transactions 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 such issuance or 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:

Latham & Watkins LLP 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:

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose 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 previously announced that it is 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. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. These rates are subject to change by new legislation at any time or as a result of sunset provisions.

The recently-enacted Patient Protection and Affordable Care Act of 2010, as amended by the Health Care and Education Reconciliation Act of 2010, is scheduled to impose a 3.8% Medicare tax on certain net investment income earned by individuals, estates and trusts for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain recognized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

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 unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” 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, the inside basis in our assets with respect to a unitholder 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. 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 straightline 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 Latham & Watkins LLP 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 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.

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 twelve months 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 an 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, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. 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.

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 that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, 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 will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at favorable rates, currently a maximum U.S. federal income tax rate of 15%. However, a portion of this gain or loss, which will likely be substantial, 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. 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 discussed above, 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 Treasury 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 Treasury 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:

in each case, with respect to the partnership interest or substantially identical property.

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

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

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 as there is no direct or indirect controlling authority on this issue. Recently, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax

items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. 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.

Technical Termination. We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A technical 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 technical termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) 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 technical termination, including a new election under Section 754 of the Internal Revenue Code, and a technical termination would result in a deferral of our deductions for depreciation. A technical termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a technical termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

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 Treasury 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. In either case, and as stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, 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.”

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 to a limited extent below, may have substantially adverse tax consequences to them. 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.

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 it.

Non-resident aliens and foreign corporations, or beneficiaries of 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 earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that 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.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected

with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

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 Latham & Watkins LLP 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:

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:

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, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted tax 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 tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. 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 of the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking “economic substance.” To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

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 6 successive 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 additional consequences:

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 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.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

An investment in our units or debt securities by an employee benefit plan is subject to certain additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended, or ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code of 1986, as amended, or the Code, and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, which we refer to collectively as Similar Laws. As used herein, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or other arrangements established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements.

ERISA and the Code impose certain duties on persons who are fiduciaries of an employee benefit plan that is subject to Title I of ERISA or Section 4975 of the Code, which we refer to as an ERISA Plan, and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of such an ERISA Plan or the management or disposition of the assets of such an ERISA Plan, or who renders investment advice for a fee or other compensation to such an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan. In considering an investment in our units or debt securities, among other things, consideration should be given to (a) whether such investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws; (b) whether in making such investment, such plan will satisfy the diversification requirement of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws; (c) whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws. and (d) whether such investment will result in recognition of unrelated business taxable income by such plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Considerations.” The person with investment discretion with respect to the assets of an employee benefit plan, which we refer to as a fiduciary, should determine whether an investment in our units or debt securities is authorized by the appropriate governing instrument and is a proper investment for such plan.

Section 406 of ERISA and Section 4975 of the Code (which also applies to IRAs that are not considered part of an employee benefit plan) prohibit an employee benefit plan from engaging in certain transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Code.

The acquisition and/or holding of the common units or debt securities by an ERISA Plan with respect to which we or the initial purchasers are considered a party in interest or a disqualified person, may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the common units or debt securities are acquired and held in accordance with an applicable statutory, class or individual prohibited transaction exemption. In this regard, the U.S. Department of Labor has issued prohibited transaction class exemptions, or PTCEs, that may apply to the acquisition, holding and, if applicable, conversion of the common units or debt securities. These class exemptions include, without limitation, PTCE 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1 respecting insurance company pooled separate accounts, PTCE 91-38 respecting bank collective investment funds, PTCE 95-60 respecting life insurance company general accounts and PTCE 96-23 respecting

transactions determined by in-house asset managers. There can be no assurance that all of the conditions of any such exemptions will be satisfied.

Because of the foregoing, the common units or debt securities should not be purchased or held (or converted to equity securities, in the case of any convertible debt) by any person investing “plan assets” of any employee benefit plan, unless such purchase and holding (or conversion, if any) will not constitute a non-exempt prohibited transaction under ERISA and the Code or similar violation of any applicable Similar Laws.

Accordingly, by acceptance of the common units or debt securities, each purchaser and subsequent transferee of the common units or debt securities will be deemed to have represented and warranted that either (i) no portion of the assets used by such purchaser or transferee to acquire and hold the common units or debt securities constitutes assets of any employee benefit plan or (ii) the purchase and holding (and any conversion, if applicable) of the common units or debt securities by such purchaser or transferee will not constitute a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code or similar violation under any applicable Similar Laws.

In addition to considering whether the purchase of our limited partnership units or debt securities is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether such plan will, by investing in our units or debt securities, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Pursuant to these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, (a) the equity interest acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered pursuant to certain provisions of the federal securities laws, (b) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons) is held by the employee benefit plans that are subject to part 4 of Title I of ERISA (which excludes governmental plans and non-electing church plans) and/or Section 4975 of the Code, IRAs and certain other employee benefit plans not subject to ERISA (such as electing church plans). With respect to an investment in our units, our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c) above (although we do not monitor the level of benefit plan investors as required for compliance with (c)). With respect to an investment in our debt securities, our assets should not be considered “plan assets” under these regulations because such securities are not equity securities or, even if they are considered to be equity securities for purposes of the Department of Labor Regulations, the investment will be expected to satisfy one or both of the requirements in (a) and (b) above.

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Code and Similar Laws should not be construed as legal advice. Plan fiduciaries contemplating a purchase of our limited partnership units or debt securities should consult with their own counsel regarding the consequences under ERISA, the Code and other Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

The validity of the securities offered in this prospectus will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Latham & Watkins LLP will also render an opinion on the material federal income tax considerations regarding the securities. If certain legal matters in connection with an offering of the securities made by this prospectus and a related prospectus supplement are passed on by counsel for the underwriters of such offering, that counsel will be named in the applicable prospectus supplement related to that offering.

The audited consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting of Energy Transfer Partners, L.P. and the audited consolidated balance sheets of Energy Transfer Partners GP, L.P. and Energy Transfer Partners, L.L.C., all incorporated by reference in this prospectus, have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in giving said reports.

We have filed a registration statement with the SEC under the Securities Act of 1933 that registers the securities offered by this prospectus. The registration statement, including the attached exhibits, contains additional relevant information about us. The rules and regulations of the SEC allow us to omit some information included in the registration statement from this prospectus.

In addition, 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 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. Information that we file later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC.

You may obtain any of the documents incorporated by reference in this 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 (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at www.energytransfer.com, or by writing or calling us at the following address:


	Per 2023 Note	Total 2023 Notes	Per 2043 Note	Total 2043 Notes
Price to Public¹	%	$	%	$
Underwriting Discount	%	$	%	$
Proceeds to Energy Transfer Partners, L.P. (Before Expenses)¹	%	$	%	$


About This Prospectus Supplement			S-1
Prospectus Supplement Summary			S-2
Ratio of Earnings to Fixed Charges			S-11
Risk Factors			S-12
Use of Proceeds			S-14
Capitalization			S-15
Description of Other Indebtedness			S-17
Description of Notes			S-25
Certain United States Federal Income Tax Considerations			S-41
Underwriting			S-46
Legal Matters			S-48
Experts			S-48
Where You Can Find More Information			S-48


	September 30, 2012
	Actual		As adjusted			As further adjusted			As further adjusted for notes offering
	(in millions)
Cash and cash equivalents(1)	$	110	$	936		$	2,072		$

Debt, including current maturities:
ETP
Revolving credit facility(2)	$	492		$1,112		$	1,112
Existing senior notes		7,692		8,657	(3)		8,657	(3)		8,657	(3)
Senior notes offered hereby		—		—			—
Transwestern
Senior notes		870		870			870			870
Southern Union
Revolving credit facility(4)		—		251			—			—
Senior notes		—		660			660			660
First mortgage bonds		—		20			—	(5)		—
Junior subordinated notes		—		600			600			600
Note payable to ETE		—		166			166			166


	September 30, 2012
	Actual			As adjusted		As further adjusted		As further adjusted for notes offering
	(in millions)
Panhandle
Term loan		—			455		306		306
Senior notes		—			1,166		1,166		1,166
Sunoco Logistics
$350 million revolving credit facility(6)		—			96		—		—
$200 million revolving credit facility(7)		—			74		—		—
$35 million revolving credit facility		—			9		9		9
Senior notes		—			1,450		2,150		2,150
Unamortized discounts and other		(13	)		518		516

Total long-term debt		9,041			16,104		16,212

Total partners’ capital		6,913			9,201		9,251		9,251
Noncontrolling interest		876			8,473		8,548		8,548

Total equity		7,789			17,674		17,799		17,799
Total capitalization	$	16,830		$	33,778	$	34,011	$


Underwriter	Principal Amount of 2023 Notes	Principal Amount of 2043 Notes
Merrill Lynch, Pierce, Fenner & Smith Incorporated	$	$
SunTrust Robinson Humphrey, Inc.
Wells Fargo Securities, LLC

Total	$	$


BofA Merrill Lynch		SunTrust Robinson Humphrey		Wells Fargo Securities


About This Prospectus			1
Energy Transfer Partners, L.P.			1
Cautionary Statement Concerning Forward-Looking Statements			2
Risk Factors			4
Use of Proceeds			32
Ratio of Earnings to Fixed Charges			33
Description of Units			34
Cash Distribution Policy			42
Description of the Debt Securities			47
Material Income Tax Considerations			54
Investments In Us By Employee Benefit Plans			69
Legal Matters			71
Experts			71
Where You Can Find More Information			71


	Page
ABOUT THIS PROSPECTUS		1
ENERGY TRANSFER PARTNERS, L.P.		1
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS		2
RISK FACTORS		4
USE OF PROCEEDS		32
RATIO OF EARNINGS TO FIXED CHARGES		33
DESCRIPTION OF UNITS		34
CASH DISTRIBUTION POLICY		42
DESCRIPTION OF THE DEBT SECURITIES		47
MATERIAL FEDERAL INCOME TAX CONSIDERATIONS		54
INVESTMENTS IN US BY EMPLOYEE BENEFIT PLANS		69
LEGAL MATTERS		71
EXPERTS		71
WHERE YOU CAN FIND MORE INFORMATION		71


SUBJECT TO COMPLETION, DATED JANUARY 14, 2013