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Filed Pursuant to Rule 424(b)(5)
Registration No. 333-183388

PROSPECTUS SUPPLEMENT DATED MAY 9, 2013

TO PROSPECTUS DATED OCTOBER 10, 2012

 

Energy Transfer Partners, L.P.

Common Units Representing Limited Partner Interests Having an Aggregate Offering Price of Up to $800,000,000

 

 

This prospectus supplement and the accompanying prospectus relate to the issuance and sale from time to time of common units representing limited partner interests having an aggregate offering price of up to $800,000,000 through the sales agents named in this prospectus supplement. These sales, if any, will be made pursuant to the terms of an equity distribution agreement between us and the sales agents, which has been filed previously as an exhibit to a current report on Form 8-K.

Under the terms of the equity distribution agreement, we also may sell common units to any sales agent as principal for its own account at a price agreed upon at the time of the sale. If we sell common units to any such sales agent as principal, we will enter into a separate terms agreement with such sales agent and we will describe that agreement in a separate prospectus supplement or pricing supplement.

Our common units trade on the New York Stock Exchange, or NYSE, under the symbol “ETP.” On May 8, 2013, the last reported sale price of our common units on the NYSE was $48.60 per unit. Sales of common units under this prospectus supplement, if any, will be made by means of ordinary brokers’ transactions through the facilities of the NYSE at market prices, in block transactions, or as otherwise agreed between us and the sales agent.

 

 

Investing in our common units involves risks. Please read “Risk Factors” on page S-3 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 our common units.

The compensation of each of the sales agents for sales of units shall be fixed at a commission rate of up to 2.0% of the gross sales price per unit. The net proceeds from any sales under this prospectus supplement will be used as described under “Use of Proceeds” in this prospectus supplement.

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

 

 

BofA Merrill Lynch
		Citigroup
				Goldman, Sachs & Co.
						RBC Capital Markets
								UBS Investment Bank

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You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus prepared by us or on our behalf. Neither we nor any sales agent have authorized anyone to provide you with additional or different information. We are not making an offer to sell our common units in any jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this document or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since these dates.

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

You should carefully read this prospectus supplement and the accompanying prospectus, including the information incorporated by reference in the prospectus, before you invest. These documents contain information you should consider when making your investment decision. None of Energy Transfer Partners, L.P., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Goldman, Sachs & Co., RBC Capital Markets, LLC or UBS Securities LLC or any of their respective representatives is making any representation to you regarding the legality of an investment in our common units by you under applicable laws. You should consult with your own advisors as to legal, tax, business, financial and related aspects of an investment in the common units.

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RISK FACTORS

An investment in our common units involves risk. You should carefully read the risk factors set forth in our, Southern Union’s and Sunoco Logistics’ Annual Report on Form 10-K for the year ended December 31, 2012 and the risk factors contained in the accompanying prospectus, together with all of the other information included in, or incorporated by reference into, this prospectus supplement and the accompanying prospectus, when evaluating an investment in our common units.

 

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USE OF PROCEEDS

We intend to use the net proceeds of this offering, after deducting sales agents’ commissions and our offering expenses, to repay amounts outstanding under our revolving credit facility, to fund capital expenditures and for general partnership purposes.

Affiliates of certain of the sales agents are lenders under our revolving credit facility. To the extent we use proceeds from this offering to repay indebtedness under our revolving credit facility, such affiliates will receive proceeds from this offering.

As of May 7, 2013, an aggregate of approximately $1.40 billion of borrowings were outstanding under our revolving credit facility, and there were an additional $86.9 million of letters of credit outstanding. The weighted average interest rate on the total amount outstanding at May 7, 2013 was 1.69%. Our revolving credit facility matures on October 27, 2016. Borrowings under our revolving credit facility have been used to fund the cash portion of the consideration of our acquisition of a 60% ownership interest in ETP Holdco Corporation completed on April 30, 2013, for capital expenditures related to pipeline construction projects and for general partnership purposes.

 

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MATERIAL TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. Although this section updates and adds information related to certain tax considerations, it should be read in conjunction with the risk factors included under the caption “Tax Risks to Common Unitholders” beginning on page 45 of the accompanying prospectus and the risk factors in our most recent Annual Report on Form 10-K, and with “Material Income Tax Considerations” in the accompanying prospectus, which provides a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units. The following discussion is limited as described under the caption “Material Income Tax Considerations” in the accompanying prospectus.

All prospective unitholders are encouraged to consult with their own tax advisors about the federal, state, local and foreign tax consequences particular to their own circumstances. In particular, ownership of common units by tax-exempt entities, including employee benefit plans and IRAs, and non-U.S. investors raises issues unique to such persons. The relevant rules are complex, and the discussions herein and in the accompanying prospectus do not address tax considerations applicable to tax-exempt entities and non-U.S. investors, except as specifically set forth in the accompanying prospectus. Please read “Material Income Tax Considerations — Tax-Exempt Organizations and Other Investors” in the accompanying prospectus.

Partnership Status

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

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids and certain related hedging activities. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 6% of our current gross income is not qualifying income. However, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income and we are classified as a partnership for U.S. federal income tax purposes. For a more complete discussion of the qualifying income requirement and the importance of our status as a partnership, please read “Material Income Tax Considerations — Partnership Status” in the accompanying prospectus.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal

 

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income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

At the state level, several states currently impose entity-level taxes on partnerships. In addition, several additional states are evaluating ways to subject partnerships to entity-level taxation through the implementation of state income, franchise or 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 and the value of an investment in our common units could be negatively impacted.

Tax Rates

Beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% 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 twelve months) of individuals is 20%. However, these rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax on net investment income earned by individuals, estates and trusts applies 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 realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income or (2) 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).

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of ETP’s income, gain, loss, or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $179,500 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 their tax advisors as to the impact of an investment in our units on their liability for the alternative minimum tax.

 

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PLAN OF DISTRIBUTION

We have entered into an equity distribution agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Goldman, Sachs & Co., RBC Capital Markets, LLC and UBS Securities LLC as our sales agents, under which we may offer and sell common units having an aggregate offering price of up to $800,000,000 from time to time. Sales of the common units, if any, will be made by means of ordinary brokers’ transactions on the NYSE at market prices, block transactions and such other transactions as agreed upon by us and the sales agents. The sales agents will not engage in any transactions that stabilize the price of our common units.

Under the terms of the equity distribution agreement, we also may sell common units to one or more of the sales agents as principal for its own account at a price agreed upon at the time of the sale. If we sell common units to a sales agent as principal, we will enter into a separate terms agreement with the sales agent, and we will describe that agreement in a separate prospectus supplement or pricing supplement.

The sales agents will use their efforts to sell the common units offered pursuant to this prospectus supplement on a daily basis or as otherwise agreed upon by us and a sales agent. We will designate the maximum number of common units to be sold through a sales agent, on a daily basis or otherwise as we and a sales agent agree. We will submit orders to only one sales agent relating to the sale of our common units on any given day. We may instruct such sales agent not to sell common units if the sales cannot be effected at or above the price designated by us in any such instruction. Either we or any sales agent may suspend the offering of common units by such sales agent pursuant to the equity distribution agreement by notifying the other party.

The commission to be paid to any sales agent for units sold through it pursuant to the equity distribution agreement shall be fixed at a commission rate of up to 2.0% of the gross sales price per unit. The remaining sales proceeds, after deducting the applicable commission and any expenses payable by us and any transaction fees imposed by any governmental or self regulatory organization in connection with the sales, will equal our net proceeds from the sale of the common units.

Settlement for sales of common units will occur on the third business day following the date on which any sales were made in return for payment of the net proceeds to us. There is no arrangement for funds to be received in an escrow, trust or similar arrangement.

In connection with the sale of the common units on our behalf, the sales agents may be deemed to be “underwriters” within the meaning of the Securities Act of 1933, as amended, or the Securities Act, and the compensation paid to the sales agents may be deemed to be underwriting commissions or discounts. We have agreed to provide indemnification and contribution to the sales agents against certain liabilities, including civil liabilities under the Securities Act. We have also agreed to reimburse the sales agents for certain of their expenses.

The sales agents and their related entities have, from time to time, performed, and may in the future perform, various financial advisory and commercial and investment banking services for us and our affiliates, for which they have received and in the future will receive customary compensation and expense reimbursement.

In addition, in the ordinary course of their business activities, the sales agents and their 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 accounts and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. If any sales agent or any of its affiliates has a lending relationship with us, one or more of the sales agents or such affiliates may hedge their credit exposure to us consistent with their customary risk management policies. Typically, such sales agents and such 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

 

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potentially the common units offered hereby. Any such short positions could adversely affect future trading prices of the common units offered hereby. The sales agents and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In compliance with the guidelines of the Financial Industry Regulatory Authority, Inc., or FINRA, the maximum discount or commission to be received by any FINRA member or independent broker-dealer may not exceed 8% of the aggregate offering price of the common units offered pursuant to this prospectus supplement. We intend to use a portion of the proceeds of this offering to repay amounts outstanding under our revolving credit facility. Affiliates of each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co., RBC Capital Markets, LLC and UBS Securities LLC are lenders under our revolving credit facility and, accordingly, may receive a portion of the proceeds of this offering. Because FINRA views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules.

If we or any of the sales agents have reason to believe that our common units are no longer an “actively-traded security” as defined under Rule 101(c)(l) of Regulation M under the Securities Exchange Act of 1934, as amended, that party will promptly notify the other and sales of common units pursuant to the equity distribution agreement or any terms agreement will be suspended until in our collective judgment Rule 101(c)(1) or another exemptive provision has been satisfied.

The offering of common units pursuant to the equity distribution agreement will terminate upon the earlier of (1) the sale of all common units subject to the equity distribution agreement or (2) the termination of the equity distribution agreement by us or by all of the sales agents.

 

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LEGAL MATTERS

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

EXPERTS

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, 2012 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.

 

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WHERE YOU CAN FIND MORE INFORMATION

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

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

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

 

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our annual report on Form 10-K for the year ended December 31, 2012;

 

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our current reports on Form 8-K filed January 14, 2013, January 16, 2013, January 22, 2013, January 23, 2013, February 28, 2013, March 11, 2013, March 26, 2013, April 4, 2013, April 10, 2013, April 17, 2013, May 1, 2013 and May 9, 2013, and our current report on Form 8-K/A filed on April 18, 2013 (excluding any information furnished pursuant to Item 2.02 or Item 7.01 of any such current reports on Form 8-K or 8-K/A);

 

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the description of our common units in our registration statement on Form 8-A (File No. 1-11727) filed pursuant to the Securities Exchange Act of 1934 on May 16, 1996; and

 

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all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this prospectus supplement and until the termination of this offering (excluding any information furnished pursuant to Item 2.02 or Item 7.01 of any current report on Form 8-K).

You may obtain any of the documents incorporated by reference in this prospectus supplement or the accompanying prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus supplement and the accompanying prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at http://www.energytransfer.com, or by writing or calling us at the address set forth below. Information on our website is not incorporated into this prospectus supplement, the accompanying prospectus or our other securities filings and is not a part of this prospectus supplement or the accompanying prospectus.

Energy Transfer Partners, L.P.

3738 Oak Lawn Avenue

Dallas, TX 75219

Attention: Thomas P. Mason

Telephone: (214) 981-0700

 

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Prospectus

 

ENERGY TRANSFER PARTNERS, L.P.

$1,000,000,000

 

 

Common Units

Debt Securities

 

 

We may offer and sell up to $1,000,000,000 in aggregate offering price of common units, representing limited partner interests of Energy Transfer Partners, L.P., and debt securities described in this prospectus from time to time in one or more classes or series and in amounts, at prices and on terms to be determined by market conditions at the time of our offerings.

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

 

 

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

Our common units are traded on the New York Stock Exchange, or the NYSE, under the symbol “ETP.” The last reported sales price of our common units on the NYSE on September 20, 2012 was $41.75 per common unit. We will provide information in the prospectus supplement for the trading market, if any, for any debt securities we may offer.

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

 

 

The date of this prospectus is October 10, 2012.

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ABOUT THIS PROSPECTUS			1
ENERGY TRANSFER PARTNERS, L.P.			1
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS			2
RISK FACTORS			4
USE OF PROCEEDS			50
RATIO OF EARNINGS TO FIXED CHARGES			51
DESCRIPTION OF UNITS			52
CASH DISTRIBUTION POLICY			60
DESCRIPTION OF THE DEBT SECURITIES			65
MATERIAL INCOME TAX CONSIDERATIONS			71
INVESTMENTS IN US BY EMPLOYEE BENEFIT PLANS			89
PLAN OF DISTRIBUTION			91
LEGAL MATTERS			93
EXPERTS			93
WHERE YOU CAN FIND MORE INFORMATION			94

 

 

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

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

 

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ABOUT THIS PROSPECTUS

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

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, Alabama, Mississippi, West Virginia, Colorado and Utah, and three natural gas storage facilities located in Texas. These assets include more than 18,000 miles of pipeline in service and a 50% interest in two joint ventures that have approximately 5,585 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 Eagle Ford Shale in south and central Texas, the San Juan Basin in New Mexico, the Fayetteville Shale in Arkansas and the Haynesville Shale in north 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 also hold a 70% interest in a joint venture that owns and operates natural gas liquids, or NGL, storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

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.

 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

 

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the amount of natural gas transported on our pipelines and gathering systems;

 

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the level of throughput in our natural gas processing and treating facilities;

 

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the fees we charge and the margins we realize for our gathering, treating, processing, storage and transportation services;

 

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the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs;

 

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energy prices generally;

 

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the prices of natural gas compared to the price of alternative and competing fuels;

 

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the level of domestic oil and natural gas production;

 

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the availability of imported oil and natural gas;

 

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actions taken by foreign oil and gas producing nations;

 

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the political and economic stability of petroleum producing nations;

 

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the effect of weather conditions on demand for oil and natural gas;

 

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availability of local, intrastate and interstate transportation systems;

 

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the continued ability to find and contract for new sources of natural gas supply;

 

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availability and marketing of competitive fuels;

 

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the impact of energy conservation efforts;

 

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energy efficiencies and technological trends;

 

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governmental regulation and taxation;

 

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changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;

 

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hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs that may not be fully covered by insurance;

 

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competition from other midstream companies and interstate pipeline companies;

 

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loss of key personnel;

 

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loss of key natural gas producers or the providers of fractionation services;

 

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reductions in the capacity or allocations of third party pipelines that connect with our pipelines and facilities;

 

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the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;

 

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the nonpayment or nonperformance by our customers;

 

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regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

 

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risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third party contractors;

 

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the availability and cost of capital and our ability to access certain capital sources;

 

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the further deterioration of the credit and capital markets;

 

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the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

 

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changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

 

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the costs and effects of legal and administrative proceedings.

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

 

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RISK FACTORS

An investment in our securities involves a high degree of risk. You should carefully consider the following risk factors, together with all of the other information included in, or incorporated by reference into, this 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.

Risks Inherent in an Investment in Us

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

The amount of cash we can distribute 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:

 

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the amount of natural gas transported in our pipelines and gathering systems;

 

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the level of throughput in our processing and treating operations;

 

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the fees we charge and the margins we realize for our gathering, treating, processing, storage and transportation services;

 

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the price of natural gas and NGLs;

 

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the relationship between natural gas and NGL prices;

 

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the amount of cash distributions we receive with respect to the AmeriGas Partners, L.P., or AmeriGas, common units that we own;

 

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the weather in our operating areas;

 

•

the level of competition from other midstream companies, interstate pipeline companies and other energy providers;

 

•

the level of our operating costs;

 

•

prevailing economic conditions; and

 

•

the level of our derivative activities.

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

 

•

the level of capital expenditures we make;

 

•

the level of costs related to litigation and regulatory compliance matters;

 

•

the cost of acquisitions, if any;

 

•

the levels of any margin calls that result from changes in commodity prices;

 

•

our debt service requirements;

 

•

fluctuations in our working capital needs;

 

•

our ability to borrow under our credit facilities;

 

•

our ability to access capital markets;

 

•

restrictions on distributions contained in our debt agreements; and

 

•

the amount, if any, of cash reserves established by our general partner in its discretion for the proper conduct of our business.

 

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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, and is not solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions during periods when we record net losses.

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:

 

•

the current proportionate ownership interest of our unitholders in us will decrease;

 

•

the amount of cash available for distribution on each common unit or partnership security may decrease;

 

•

the relative voting strength of each previously outstanding common unit may be diminished; and

 

•

the market price of the common units or partnership securities may decline.

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 June 30, 2012, Energy Transfer Equity, L.P., or ETE, directly and indirectly owned an aggregate of 52,476,059 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 2012, we filed a registration statement, in which this prospectus is included, 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 June 30, 2012, we had approximately $9.15 billion of consolidated debt, excluding the credit facilities of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

 

•

a significant portion of our cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

 

•

covenants contained in our existing debt agreements require us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

 

•

our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

 

•

we may be at a competitive disadvantage relative to similar companies that have less debt;

 

•

we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

 

•

failure to comply with the various restrictive covenants of our debt agreements could negatively impact our ability and the ability of our subsidiaries to incur additional debt, including our ability to utilize the available capacity under our revolving credit facilities, and our ability to pay our distributions.

 

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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 June 30, 2012, we had approximately $9.15 billion of consolidated debt, excluding the credit facilities of our joint ventures. 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 changes in interest rates. As of June 30, 2012, we had approximately $9.15 billion of consolidated debt, excluding the credit facilities of our joint ventures. Approximately $493.4 million of our consolidated debt bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.

As of June 30, 2012, we had a total of $800 million of notional amount of forward-starting interest rate swaps outstanding to hedge the anticipated issuance of senior notes in 2013 and 2014. In addition, we had a total of $600 million of notional amount of interest rate swaps that swap a portion of our fixed rate debt to floating.

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 the partnership 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, ETP GP and 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.

 

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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 66 2/3% of the outstanding units voting together as a single class, including units owned by the general partner and its affiliates. As of June 30, 2012, ETE and its affiliates held approximately 23% of our outstanding units, with an additional approximate 0.24% of our outstanding units held by our officers and directors. Consequently, it could be difficult to remove the general partner without the consent of the general partner and our 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.

The 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 any interruption of distributions to us may affect our ability to meet our obligations and 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.

 

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Unitholders may have liability to repay distributions.

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

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 at maturity of the notes, 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.

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

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash to our unitholders of record and our general partner. Available Cash is generally all of our cash on hand as of the end of a 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:

 

•

to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);

 

•

to provide funds for distributions to our unitholders and our general partner for any one or more of the next four calendar quarters; or

 

•

to comply with applicable law or any of our loan or other agreements.

Risks Related to Conflicts of Interest

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

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates and 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:

 

•

permits our general partner to make a number of decisions in its “sole discretion.” This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

 

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•

provides that our general partner is entitled to make other decisions in its “reasonable discretion;”

 

•

generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; and

 

•

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

In order to become a limited partner of our partnership, a unitholder is required to agree to be bound by the provisions in our 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, our 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 indirectly 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.

Such conflicts may arise from, among others, the following:

 

•

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other

 

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duties under applicable state law. Our general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

 

•

Our general partner is allowed to take into account the interests of parties in addition to us, including ETE, Regency and their affiliates, in resolving conflicts of interest, thereby limiting its fiduciary duties to us.

 

•

Our general partner’s affiliates, including ETE, Regency and their affiliates, are not prohibited from engaging in other businesses or activities, including those in direct competition with us.

 

•

Our general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can affect the amount of cash that is distributed to unitholders and to ETE.

 

•

Neither our partnership agreement nor any other agreement requires ETE or its affiliates, including Regency, to pursue a business strategy that favors us. The directors and officers of the general partners of ETE and Regency have a fiduciary duty to make decisions in the best interest of their members, limited partners and unitholders, which may be contrary to our best interests.

 

•

Some of the directors and officers of ETE who provide advice to us also may devote significant time to the businesses of ETE, Regency and their affiliates and will be compensated by them for their services.

 

•

Our general partner determines which costs, including allocated overhead costs, are reimbursable by us.

 

•

Our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is fair and reasonable to us will be deemed approved by all partners and will not constitute a breach of the partnership agreement.

 

•

Our general partner controls the enforcement of obligations owed to us by it.

 

•

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

•

Our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

 

•

Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us.

 

•

In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

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. We cannot assure unitholders that such conflicts will not occur or that our internal conflicts policy will be effective in all circumstances to protect our commercially sensitive information or to realize the commercial value of our business opportunities.

Affiliates of our general partner may compete with us.

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

 

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with us. Regency 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.

Risks Related to Our Business

We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.

Certain of our joint ventures have their own governing boards, and we may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in our or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture.

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 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 percent-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 percent-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 to 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.

 

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In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX settlement price for the prompt month contract ranged from a high of $4.38 per MMBtu to a low of $3.36 per MMBtu. A composite of the Mont Belvieu average NGLs price based upon our average NGLs composition during our year ended December 31, 2011 ranged from a high of approximately $1.36 per gallon to a low of approximately $1.15 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 on our pipelines 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 impact of weather on the demand for oil and natural gas;

 

•

the level of domestic oil and natural gas production;

 

•

the availability of imported oil and natural gas;

 

•

actions taken by foreign oil and gas producing nations;

 

•

the availability of local, intrastate and interstate transportation systems;

 

•

the price, availability and marketing of competitive fuels;

 

•

the demand for electricity;

 

•

the impact of energy conservation efforts; and

 

•

the extent of governmental regulation and taxation.

The profitability of certain activities in our NGL and refined products storage business, our NGL transportation business and our off-gas processing and fractionating business are largely dependent upon market demand for NGLs and refined products, which has been volatile, and competition in the market place, both of which are factors that are beyond our control.

Our NGL and refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers. However, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers. Demand for these services may fluctuate as a result of changes in commodity prices. Our NGL and refined products storage assets are primarily located in the Mont Belvieu area, which is a significant storage distribution and trading complex with multiple industry participants, any one of which could compete for the business of our existing and potential customers. Any loss of business from existing customers or our inability to attract new customers could have an adverse effect on our results of operations.

Revenue from our NGL transportation systems is exposed to risks due to fluctuations in demand for transportation as a result of unfavorable commodity prices and competition from nearby pipelines. We receive

 

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substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation system. We may not be able to renew these contracts or execute new customer contracts on favorable terms if NGL prices decline and demand for our transportation services decreases. Any loss of existing customers due to decreased demand for our services or competition from other transportation service providers could have a negative impact on our revenues and have an adverse effect on our results of operations.

Revenue from our off-gas processing and fractionating system in south Louisiana is exposed to risks due to the low concentration of suppliers near our facilities and the possibility that connected refineries may not provide us with sufficient off-gas for processing at our facilities. The connected refineries may also experience outages due to maintenance issues and severe weather, such as hurricanes. We receive revenues primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

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 impact of weather on the demand for oil, natural gas and NGLs;

 

•

the level of domestic oil and natural gas production;

 

•

the availability of imported oil, natural gas and NGLs;

 

•

actions taken by foreign oil and gas producing nations;

 

•

the availability of local transportation systems;

 

•

the price, availability and marketing of competitive fuels;

 

•

the demand for electricity;

 

•

the impact of energy conservation efforts; and

 

•

the extent of governmental regulation and taxation.

The use of derivative financial instruments could result in material financial losses by 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 trading, 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

 

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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 interstate segment derives a significant portion of its revenue from charging its customers for reservation of capacity, which revenues it receives regardless of whether these customers actually use the reserved capacity. Our interstate segment also generates revenue from transportation of natural gas for customers without reserved capacity. If the reserves available through the supply basins connected to our interstate pipelines 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 our interstate pipelines 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, 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

 

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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.

As of June 30, 2012, our consolidated balance sheet reflected $600.2 million of goodwill and $170.1 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.

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:

 

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because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

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because we are unable to raise financing for such acquisitions on economically acceptable terms; or

 

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because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

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:

 

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fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

 

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decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

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significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

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•

encounter difficulties operating in new geographic areas or new lines of business;

 

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incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

 

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be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;

 

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less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or

 

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incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

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:

 

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we are unable to identify pipeline construction opportunities with favorable projected financial returns;

 

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we are unable to raise financing for our identified pipeline construction opportunities; or

 

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we are unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if 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. 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, may 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

 

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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 the year ended December 31, 2011, EnCana Oil and Gas (USA), Inc., Rosetta Resources Operating LP, EnerVest Operating, LLC, and SandRidge Energy Inc. supplied us with approximately 67% of the Southeast Texas System’s natural gas supply. For our year ended December 31, 2011, EOG Resources, Inc., affiliates of Chesapeake Energy Corporation, XTO Energy Inc. (“XTO”) and EnCana Oil and Gas (USA), Inc., supplied us with approximately 76% 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 several nine- and ten-year fee-based transportation contracts with XTO that terminate through 2019, pursuant to which XTO has committed to transport certain minimum volumes of natural gas on pipelines in our ET Fuel System. We also have an eight-year fee-based transportation contract with Luminant Energy Company LLC (“Luminant”) to transport natural gas on the ET Fuel System. We have also entered into two eight-year natural gas storage contracts that terminate in 2015 with Luminant to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with Luminant may be extended by Luminant for an additional one-year term.

During 2011, Natural Gas Exchange, Inc., EDF Trading North America, Inc., XTO Energy, Inc. and ConocoPhillips collectively accounted for approximately 30% of our intrastate transportation and storage revenues.

With respect to our interstate transportation operations, FEP, an entity in which we own a 50% interest, has 10-12 year agreements 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 project. 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 other shippers that provide for 10-year commitments for firm transportation capacity on the Tiger pipeline totaling approximately 1.4 Bcf/d, bringing the total shipper commitments to approximately 2.4 Bcf/d of firm transportation service in the Tiger pipeline project. Transwestern Pipeline Company, LLC, or 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 2011, Chesapeake Energy Marketing, Inc., EnCana Marketing (USA), Inc. (“EnCana”), Shell Energy North America (US), L.P. and Pacific Summit Energy LLC collectively accounted for 37% of our interstate 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.

 

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Certain of our assets may become subject to regulation.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. The West Texas Pipeline, which we acquired as part the LDH acquisition, transports NGLs within the state of Texas and is subject to regulation by the Texas Railroad Commission, or the TRRC. This NGL transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. Such services must be provided in a manner that is just, reasonable and non-discriminatory. We believe that this NGL system does not currently provide interstate service and that it is thus not subject to FERC jurisdiction under the Interstate Commerce Act (the “ICA”) and the Energy Policy Act of 1992. We cannot guarantee that the jurisdictional status of this NGL pipeline system will remain unchanged. If the West Texas Pipeline became subject to regulation by FERC, pursuant to the ICA, FERC’s rate-making methodologies may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

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 FERC regulation under 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 NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than our currently approved rates, we may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, and failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

FERC has adopted 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 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, 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 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

 

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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 DOT, 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 FERC. The rates charged by natural gas companies are generally required to be on file with FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. 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, FERC has the ability, on a prospective basis, to order refunds of amounts collected under rates that have been found by FERC to be in excess of a just and reasonable level.

On September 21, 2011, in lieu of filing a new general rate case filing under Section 4 of the NGA, Transwestern filed a proposed settlement with FERC, which was approved by FERC on October 31, 2011. Transwestern is required to file a new general rate case on October 1, 2014. However, shippers which were not parties to the settlement have the right to challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates absent shipper complaint.

 

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Some of the shippers on our interstate pipelines pay rates established pursuant to long-term, negotiated rate transportation agreements. Prospective shippers on our interstate pipelines that elect not to pay a negotiated rate for service may instead choose to pay a cost-based recourse rate. 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.

Any successful challenge to the rates of our interstate natural gas companies, whether the result of a 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 FERC and the courts, and FERC’s current policy is subject to future refinement or change.

The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. It is currently FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Under 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 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 end of the term of our 2011 rate case settlement.

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

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

 

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terms and conditions of service;

 

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the types of services interstate pipelines may offer their customers;

 

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construction of new facilities;

 

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acquisition, extension or abandonment of services or facilities;

 

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reporting and information posting requirements;

 

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accounts and records; and

 

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relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair 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 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

 

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pipelines we were required to, among other things, file and support before FERC NGA Section 7(c) applications for certificates of public convenience and necessity to build, own and operate such facilities. We cannot guarantee that FERC will authorize construction and operation of any future interstate natural gas transportation project we might propose. Moreover, there is no guarantee that certificate authority for 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, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC possesses similar authority under the NGPA.

Finally, 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 NGL 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 (“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 liability 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 2025 was $5.7 million as of December 31, 2011.

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. 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.

 

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Recently finalized rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA finalized a set of rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes revised New Source Performance Standards (“NSPS”) to address volatile organic compounds (“VOCs”) and sulfur dioxide emissions at natural gas processing plants. A separate set of emission standards address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, pneumatic controllers, dehydrators, storage tanks and other production equipment. In addition, the rules specify revised and more stringent leak detection requirements for natural gas processing plants. These rules will require a number of modifications to our operations, including the installation of new equipment, although the compliance deadline for some of these rules is deferred until January 1, 2015 and other requirements will apply only to facilities that are newly constructed, reconstructed, or substantially modified. We are still evaluating the effect of these rules on our operations, but we expect that they could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

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.

In December 2009, the EPA determined 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. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half 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. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, natural gas or NGLs. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

 

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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 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 financial reform 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 legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission, or CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s position limits rules will become effective on October 12, 2012, although there is a pending legal proceeding seeking to enjoin those rules. The rules will impose certain position limits for spot month positions; at this time the CFTC has not established limits for non-spot month or combined month positions. Certain CFTC reporting and recordkeeping rules will become effective beginning October 12, 2012, for swap dealer entities. End user compliance with reporting rules and permanent recordkeeping rules is expected to begin 180 days after October 12, 2012. 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.

 

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We may be impacted by competition from other midstream and transportation and storage 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, 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.

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.

 

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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, 2011, approximately 31% 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 natural gas storage business may depend on neighboring pipelines to transport natural gas.

To obtain natural gas, our natural gas 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 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 $3.4 million and operating and maintenance costs of $17.9 million over the course of the next

 

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year. For the years ended December 31, 2011, 2010 and 2009, $18.3 million, $13.3 million and $31.4 million, respectively, of capital costs and $14.7 million, $15.4 million and $18.5 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 from time to time in the U.S. Congress, and we cannot predict whether and to what extent such measures may be enacted in the future. The DOT has also 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 and to increase enforcement efforts, including issuance of corrective action orders. Such Legislative and regulatory actions could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

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.

 

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We have a significant equity investment in AmeriGas and the value of this investment, and the cash distributions we expect to receive from this investment, are subject to the risks encountered by AmeriGas with respect to its business.

In January 2012, we consummated the contribution of our propane business to AmeriGas in exchange for consideration of approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units, plus the assumption of approximately $71 million of existing Heritage Operating, L.P. debt. The value of our investment in AmeriGas common units and the cash distributions we expect to receive on a quarterly basis with respect to these common units are subject to the risks encountered by AmeriGas with respect to its business, including the following:

 

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adverse weather condition resulting in reduced demand;

 

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cost volatility and availability of propane, and the capacity to transport propane to its customers;

 

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the availability of, and its ability to consummate, acquisition or combination opportunities;

 

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successful integration and future performance of acquired assets or businesses;

 

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changes in laws and regulations, including safety, tax, consumer protection and accounting matters;

 

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competitive pressures from the same and alternative energy sources;

 

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failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues;

 

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liability for environmental claims;

 

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increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand;

 

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adverse labor relations;

 

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large customer, counter-party or supplier defaults;

 

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liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to transporting, storing and distributing propane, butane and ammonia;

 

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political, regulatory and economic conditions in the United States and foreign countries;

 

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capital market conditions, including reduced access to capital markets and interest rate fluctuations;

 

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changes in commodity market prices resulting in significantly higher cash collateral requirements;

 

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the impact of pending and future legal proceedings;

 

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the timing and success of its acquisitions and investments to grow its business; and

 

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its ability to successfully integrate acquired businesses and achieve anticipated synergies.

Our pipelines may be subject to more stringent safety regulation.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, became effective. The new law requires more stringent oversight of pipelines and increased civil penalties for violations of pipeline safety rules. The law requires numerous studies and/or the development of rules over the next two years covering the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related rules. The DOT has already proposed rules that address many areas of the newly adopted legislation. Any 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.

 

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Risks Relating to the Sunoco Merger and the Holdco Restructuring

Our acquisition of Sunoco and the Holdco restructuring are subject to the satisfaction of certain conditions to closing.

On April 30, 2012, we announced our entry into a definitive merger agreement whereby we will acquire Sunoco Inc., or Sunoco, in a common unit and cash transaction valued at $5.3 billion based on our unit closing price on April 27, 2012 (the “Sunoco merger”). This transaction is expected to close in the third or fourth quarter of 2012, subject to approval by Sunoco’s shareholders and customary regulatory approvals.

Under the Sunoco merger agreement, immediately prior to, or contemporaneously with, the effective time of the merger, Sunoco will contribute:

 

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the equity interests of Sunoco Partners LLC (which currently holds the 2% general partner interest, incentive distribution rights, and 32.4% limited partner interest in Sunoco Logistics Partners L.P., or Sunoco Logistics) to us in exchange for 50,706,000 newly issued ETP Class F units, and

 

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its cash on hand to us in exchange for a number of newly issued ETP Class F units equal to the amount of such cash divided by $50.00.

We refer to this transaction as the “Sunoco Logistics restructuring,” and the Sunoco Logistics restructuring will only occur if all of the conditions to the closing of the Sunoco merger have been satisfied or waived. For a description of the Class F units, please read “Description of Units — Common Units, Class E Units, Class F Units and General Partner Interest” and “Cash Distribution Policy.”

On June 15, 2012, following the approval of (i) the conflicts committee of the board of directors of Energy Transfer Partners, L.L.C., the general partner of Energy Transfer Partners GP, L.P., our general partner, or the ETP board of directors, (ii) the ETP board of directors, (iii) the special committee and the conflicts committee of the board of directors of LE GP, LLC, the general partner of ETE, or the ETE board of directors, and (iv) the ETE board of directors, we, ETE and our respective relevant subsidiaries entered into a transaction agreement, pursuant to which, immediately following the closing of the Sunoco merger and the Sunoco Logistics restructuring, (a) ETE will contribute its interest in Southern Union Company, or Southern Union, to ETP Holdco Corporation, or Holdco, an indirect wholly owned subsidiary of ETP, in exchange for a 60% equity interest in Holdco and (b) we will contribute Sunoco (exclusive of our interests in Sunoco Logistics) to Holdco and will retain a 40% equity interest in Holdco. We refer to the transactions contemplated by the transaction agreement as the “Holdco restructuring.”

Our acquisition of Sunoco Inc. is subject to the satisfaction of certain conditions to closing, including the adoption of the Sunoco merger agreement by the shareholders of Sunoco, the receipt of required regulatory approvals, the effectiveness of a registration statement on Form S-4 relating to the ETP common units to be issued in connection with the merger, and the absence of any law, injunction, judgment or ruling prohibiting or restraining the Sunoco merger or making the consummation of the Sunoco merger illegal. In the event those conditions to closing are not satisfied or waived, we would not complete the acquisition of Sunoco Inc.

Additionally, the Holdco restructuring is subject to the satisfaction of certain conditions to closing, including the closing of the Sunoco merger. We cannot predict with certainty whether and when these conditions will be satisfied. Any delay in completing the merger, and thereby the Holdco restructuring, could cause us not to realize, or delay the realization, of some or all of the benefits of the Sunoco merger and the Holdco restructuring.

 

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Any acquisition we complete, including the Sunoco merger, is subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.

Any acquisition we complete, including the proposed Sunoco acquisition, involves potential risks, including, among other things:

 

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the validity of our assumptions about revenues, capital expenditures and operating costs of the acquired business or assets, as well as assumptions about achieving synergies with our existing businesses;

 

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the validity of our assessment of environmental liabilities, including legacy liabilities;

 

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a significant increase in our interest expense and financial leverage resulting from any additional debt incurred to finance the acquisition consideration, which could offset the expected accretion to our unitholders from such acquisition and could be exacerbated by volatility in the credit or debt capital markets;

 

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a failure to realize anticipated benefits, such as increased distributable cash flow per unit, enhanced competitive position or new customer relationships;

 

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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;

 

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difficulties operating in new geographic areas or new lines of business;

 

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the incurrence or assumption of unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

 

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the inability to hire, train or retrain qualified personnel to manage and operate our growing business and assets, including any newly acquired business or assets;

 

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the diversion of management’s attention from our existing businesses; and

 

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the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

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.

Also, our reviews of businesses or assets proposed to be acquired are inherently incomplete because it generally is not feasible to perform an in-depth review of businesses and assets involved in each acquisition given time constraints imposed by sellers. Even a detailed review of assets and businesses may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the assets or businesses to fully assess their deficiencies and potential. Inspections may not always be performed on every asset, and environmental problems are not necessarily observable even when an inspection is undertaken.

The completion of the Sunoco merger and the Holdco restructuring may require us to obtain debt or equity financing, or a combination thereof, which may not be available to us on acceptable terms, or at all.

The Sunoco merger agreement requires that we pay Sunoco shareholders a combination of cash and ETP common units as consideration for Sunoco common shares. We plan to fund the cash payment partially with Sunoco’s cash on hand and with borrowings under our amended and restated revolving credit facility. The incurrence of this additional indebtedness will increase our overall level of debt and adversely affect our ratios of total indebtedness to EBITDA and EBITDA to interest expense, both on a current basis and a pro forma basis taking into account our merger with Sunoco. As of June 30, 2012, our unaudited pro forma condensed consolidated long-term debt (including current maturities) after giving effect to the Sunoco merger and the

 

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Holdco restructuring would have been approximately $15.8 billion. If we are unable to finance the cash portion of the consideration for the Sunoco merger with borrowings under our amended and restated revolving credit facility, we could be required to seek alternative financing, the terms of which may not be attractive to us, or we may be unable to fulfill our obligations under the Sunoco merger agreement.

Pending litigation against us and Sunoco could result in an injunction preventing completion of the merger, the payment of damages in the event the merger is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the Sunoco merger.

In connection with the Sunoco merger, purported shareholders of Sunoco have filed several shareholder class action lawsuits against us, Sunoco, the Sunoco board of directors and others. Among other remedies, the plaintiffs seek to enjoin the Sunoco merger. If a final settlement is not reached, or if a dismissal is not obtained, these lawsuits could prevent or delay completion of the Sunoco merger and result in substantial costs to us and Sunoco, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against us and/or Sunoco related to the Sunoco merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company’s business, financial condition or results of operations.

Failure to successfully combine our businesses and the businesses of Sunoco in the expected time frame may adversely affect our future results, which may adversely affect the value of our common units that Sunoco shareholders would receive in the Sunoco merger.

The success of the Sunoco merger will depend, in part, on our ability to realize the anticipated benefits from combining our businesses with the businesses of Sunoco. To realize these anticipated benefits, our and Sunoco’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

We and Sunoco, including our respective subsidiaries, have operated and, until the completion of the merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect the combined company’s ability to maintain relationships with customers and employees after the merger or to achieve the anticipated benefits of the merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of us and Sunoco.

The Sunoco merger and related transactions could trigger substantial tax liabilities for Sunoco and Sunoco shareholders.

In January 2012, Sunoco distributed the shares of SunCoke Energy, Inc., or SunCoke, to Sunoco shareholders in a transaction intended to qualify as a tax-free spin-off for U.S. federal income tax purposes. We refer to this transaction as the “Spin-Off.” Prior to consummating the Spin-Off, Sunoco received an opinion from Wachtell, Lipton, Rosen & Katz, special counsel to Sunoco, and a private letter ruling from the Internal Revenue Service, or IRS, in each case, to the effect that the Spin-Off qualified as a transaction that is described in Sections 355(a) and 368(a)(1)(D) of the Internal Revenue Code. The U.S. federal income tax treatment of the Spin-Off depends, among other things, on the Spin-Off not being part of a plan (or series of related transactions) pursuant to which one or more persons acquire, directly or indirectly, a 50% or greater interest in Sunoco or SunCoke, and Sunoco and SunCoke made representations in support of the tax opinion to the effect that, among other things, the Spin-Off was not part of such a plan (or series of related transactions). In the event the Sunoco merger were treated as part of a plan (or series of related transactions) that includes the Spin-Off, or any other requirements necessary for tax-free treatment were not satisfied, the Spin-Off would be taxable to Sunoco (and, possibly, the

 

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Sunoco shareholders) and Sunoco would recognize a substantial amount of taxable gain. Neither we nor Sunoco has requested a ruling from the IRS or an opinion of counsel regarding the impact of the Sunoco merger on the U.S. federal income tax treatment of the Spin-Off, and there can be no assurance that the IRS will not assert that the Spin-Off is taxable as a result of the Sunoco merger. If the Spin-Off is treated as a taxable transaction for U.S. federal income tax purposes, it could negatively impact the value of our investment in Sunoco.

In addition, under proposed Treasury Regulations, which if finalized in their current form would be effective for the calendar year during which the Sunoco merger occurs and subsequent calendar years, Sunoco could be treated as redeeming a portion of the Sunoco common stock acquired by us pursuant to the Sunoco merger in exchange for ETP Class F units received by Sunoco pursuant to the Sunoco Logistics restructuring. In the event the proposed Treasury Regulations were finalized in a manner that applied to the Sunoco merger, or the IRS were to prevail with an assertion that the principles of the proposed Treasury Regulations apply to the Sunoco merger, Sunoco would recognize taxable gain to the extent that the fair market value of the assets deemed distributed in redemption of Sunoco common stock exceeded the adjusted tax basis of such assets. Such deemed redemption could also result in the receipt of a deemed distribution by us. Such a deemed distribution would be treated as a dividend to the extent of Sunoco’s current and accumulated earnings and profits, and as a return of capital to the extent of our basis in its Sunoco common stock. Any portion of the deemed distribution in excess of such basis would be treated as gain from the sale or exchange of Sunoco stock, and would be allocated to former Sunoco shareholders to the extent such gain is attributable to any “built-in gain” in their Sunoco common stock that was realized but not recognized as a result of the Sunoco merger. If Sunoco recognizes taxable gain from such deemed redemption for U.S. federal income tax purposes, it could negatively impact the value of our investment in Sunoco.

Risks Relating to Sunoco

Volatility in refined product margins could materially affect Sunoco’s business, operating results and the likelihood of Sunoco’s successful completion of a sale of Sunoco’s refining assets and the ultimate value which may be realized upon such sale.

The profitability of Sunoco’s refining business depends to a large extent upon the relationship between the acquisition price for crude oil and other feedstocks that Sunoco uses in its refineries, and the wholesale prices at which Sunoco sells its refined products. The volatility of prices for crude oil and other feedstocks and refined products, and the overall balance of supply and demand for these commodities, could have a significant impact on this relationship. Retail marketing margins also have been volatile, and vary with wholesale prices, the level of economic activity in Sunoco’s marketing areas and as a result of various logistical factors. Although an increase or decrease in the price for crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. In many cases, it is very difficult to increase refined product prices quickly enough to recover increases in the costs of products being sold. The effect of changes in crude oil prices on operating results therefore depends in part on how quickly refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, or a substantial or prolonged decrease in demand for refined products could have a significant negative effect on Sunoco’s earnings and cash flows.

 

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Sunoco may experience significant changes in its results of operations due to planned or announced additions to refining capacity by its competitors, variations in the level of refined product imports into the United States, changes in product mix (including increasing usage of renewable biofuels) or competition in pricing. Demand for the refined products Sunoco manufactures also may be reduced due to a local or national recession, or other adverse economic conditions, resulting in lower spending by businesses and consumers on gasoline and diesel fuel. In addition, Sunoco’s profit margins may decline as a direct result of unpredictable factors in the global marketplace, many of which are beyond Sunoco’s control, including:

 

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Cyclical nature of the businesses in which Sunoco operates: Refined product inventory levels and demand, crude oil price levels and availability and refinery utilization rates are all cyclical in nature. Historically, the refining industry has experienced periods of actual or perceived inadequate capacity and tight supply, causing prices and profit margins to increase, and periods of actual or perceived excess capacity, resulting in oversupply and declining capacity utilization rates, prices and profit margins. Sunoco is currently in a period of oversupply, largely as a result of reduced gasoline demand in North America and over capacity in Europe and North America. The cyclical nature of this business results in volatile profits and cash flows over the business cycle. Additionally, due to the seasonality of refined products markets and refinery maintenance schedules, results of operations for any particular quarter of a fiscal year are not necessarily indicative of results for the full year.

 

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Changes in energy and raw material costs: Sunoco purchases large amounts of energy and raw materials for its businesses. The aggregate cost of these purchases represents a substantial portion of Sunoco’s cost of doing business. The prices of energy and raw materials generally follow price trends for crude oil and natural gas, which may be highly volatile and cyclical. Furthermore, across Sunoco’s businesses, there are a limited number of suppliers for some of Sunoco’s raw materials and utilities and, in some cases, the number of sources for and availability of raw materials are specific to the particular geographic region in which a facility is located. Accordingly, if one of these suppliers were unable to meet its obligations under present supply arrangements or were unwilling to sell to Sunoco, Sunoco could suffer reduced supplies or be forced to incur increased costs for its raw materials.

 

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Geopolitical instability: Instability in the global economic and political environment can lead to volatility in the costs and availability of energy and raw materials, and in the prices for refined products. This may place downward pressure on Sunoco’s results of operations. This is particularly true of developments in and relating to oil-producing countries, including terrorist activities, military conflicts, embargoes, internal instability or actions or reactions of governments in anticipation of, or in response to, such developments.

 

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Changes in transportation costs: Sunoco utilizes the services of third parties to transport crude oil and refined products to and from its refineries. If Sunoco exits the refining business, it will likely continue to require those services for the acquisition of gasoline and diesel for its retail marketing business. The cost of these services is significant and prevailing rates can be very volatile depending on market conditions. Increases in crude oil or refined product transportation rates could result in increased raw material costs or product distribution costs. Sunoco’s operating results also may be affected by refined product and crude oil pipeline throughput capacities, and accidents or interruptions in transportation.

 

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Impact of environmental and other regulations affecting the composition of gasoline and other refined products: Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, also have a significant impact on Sunoco’s activities. Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require additional capital expenditures or expenses by Sunoco. Sunoco may have to enter into arrangements with other parties to meet its obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If Sunoco is unable to obtain or maintain sufficient quantities of ethanol to support its blending needs, its sale of ethanol blended gasoline could be interrupted or

 

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suspended which could result in lower profits. There also will be compliance costs related to these regulations. Sunoco may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that Sunoco supplies. This potential increase in supply of gasoline and diesel could result in lower refining margins for us, particularly in the event of a contemporaneous reduction in demand, or during periods of sustained low demand for such refined products. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that Sunoco markets and sells.

It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco’s business or results of operations.

Changes in general economic, financial and business conditions could have a material effect on Sunoco’s business or results of operations.

Weakness in general economic, financial and business conditions can lead to a decline in the demand for the refined products that Sunoco sells. Such weakness can also lead to lower demand for transportation and storage services provided by Sunoco. It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco’s business or results of operations.

Weather conditions and natural disasters could materially and adversely affect Sunoco’s business and operating results.

The effects of weather conditions and natural disasters can lead to volatility in the costs and availability of energy and raw materials, which can negatively impact Sunoco’s operations or those of its customers and suppliers.

Sunoco’s inability to obtain adequate supplies of crude oil could affect its business in a materially adverse way.

Sunoco currently meets all of its crude oil requirements through purchases from third parties. Most of the crude oil processed at its refineries is light-sweet crude oil. It is possible that an adequate supply of crude oil or other feedstocks may not be available to Sunoco’s refineries to sustain its current level of refining operations. In addition, Sunoco’s inability to process significant quantities of less-expensive heavy-sour crude oil could be a competitive disadvantage.

Sunoco purchases crude oil from different regions throughout the world, including a significant portion from West Africa, and Sunoco is subject to the political, geographic and economic risks of doing business with suppliers located in these regions, including:

 

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trade barriers;

 

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national and regional labor strikes;

 

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political unrest;

 

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•

increases in duties and taxes;

 

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changes in contractual terms; and

 

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changes in laws and policies governing foreign companies.

Substantially all of these purchases are made in the spot market, or under short-term contracts. In the event that Sunoco is unable to obtain crude oil in the spot market, or one or more of its supply arrangements is terminated or cannot be renewed, Sunoco will need to find alternative sources of supply. In addition, Sunoco could experience an interruption of supply or an increased cost to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of accidents, governmental regulation or third-party action. If Sunoco cannot obtain adequate crude oil volumes of the type and quality it requires, or if Sunoco is able to obtain such types and volumes only at unfavorable prices, its results of operations could be affected in a materially adverse way.

If Sunoco completes its exit from the refining business, Sunoco will be entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for its retail marketing business.

Currently, a substantial percentage of the refined products Sunoco sells in its retail marketing facilities in the northeast United States are manufactured at its refinery in Philadelphia, PA. After Sunoco’s planned exit from refining operations, it will be required to purchase these products from other manufacturers. Sunoco may also need to contract for new ships, barges, pipelines or terminals which Sunoco has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at prices no less favorable than the market-based transfer price between Sunoco’s refining and supply and retail marketing business segments or the failure of Sunoco’s suppliers to deliver product in accordance with Sunoco’s supply agreements may have a material adverse impact on Sunoco’s business or results of operations.

The adoption of derivatives legislation by the United States Congress could have an adverse effect on Sunoco’s ability to hedge risks associated with its business.

Sunoco uses swaps, options, futures, forwards and other derivative instruments to hedge a variety of commodity price risks and to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in what Sunoco considers to be acceptable margins for various refined products and to lock in the price of a portion of Sunoco’s electricity and natural gas purchases or sales and transportation costs. Sunoco does not hold or issue derivative instruments for speculative purposes. The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as Sunoco, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and required the Commodities Futures Trading Commission, or CFTC, and the United States Securities and Exchange Commission, or SEC, to promulgate rules and regulations implementing the new legislation. The CFTC also has 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 Sunoco to comply with margin requirements in connection with its derivative activities, although the application of those provisions to Sunoco is uncertain at this time. The financial reform legislation also requires many counterparties to Sunoco’s 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 requirements to post collateral, which could adversely affect Sunoco’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks Sunoco encounters, reduce Sunoco’s ability to monetize or restructure its existing derivative contracts, and increase its exposure to less creditworthy counterparties. If Sunoco reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its

 

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ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Sunoco’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on Sunoco, its financial condition, and its results of operations.

Sunoco depends upon Sunoco Logistics for a substantial portion of the logistics network that serves its refineries and Sunoco owns a significant equity interest in Sunoco Logistics.

Sunoco indirectly owns a 2% general partner interest in Sunoco Logistics, as well as all of the incentive distribution rights and a 32.4% limited partner interest in Sunoco Logistics. Sunoco Logistics owns and operates refined product and crude oil pipelines and terminals and conducts crude oil and refined product acquisition and marketing activities. Sunoco Logistics generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by charging fees for terminalling and storing refined products and crude oil and by purchasing and selling crude oil and refined products. Sunoco Logistics serves Sunoco’s refineries under long-term pipelines and terminals, storage and throughput agreements. Furthermore, Sunoco’s financial statements include the consolidated results of Sunoco Logistics. Sunoco Logistics is subject to its own operating and regulatory risks, including, but not limited to:

 

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its reliance on its significant customers, including Sunoco;

 

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competition from other pipelines;

 

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environmental regulations affecting pipeline operations;

 

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operational hazards and risks;

 

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pipeline tariff regulations affecting the rates it can charge;

 

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limitations on additional borrowings and other restrictions due to its debt covenants; and

 

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other financial, operational and legal risks.

The occurrence of any of these risks could directly or indirectly affect Sunoco Logistics’, as well as Sunoco’s, financial condition, results of operations and cash flows as Sunoco Logistics is a consolidated subsidiary of Sunoco. Additionally, these risks could affect Sunoco Logistics’ ability to continue operations, which could affect its ability to serve Sunoco’s logistics network needs.

A material decrease in demand or distribution of crude oil or refined products available for transport through Sunoco Logistics’ pipelines or terminal facilities could materially and adversely affect Sunoco’s financial position, results of operations or cash flows.

The volume of crude oil transported through Sunoco Logistics’ crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to Sunoco’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in Sunoco Logistics’ crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all.

Similarly, a decrease in market demand for refined products could also impact throughput at Sunoco Logistics’ pipelines and terminals. Material factors that could lead to a sustained decrease in market demand for refined products include a sustained recession or other adverse economic condition that results in lower purchases of refined petroleum products, higher refined products prices due to an increase in the market price of

 

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crude oil, changes in economic conditions or other factors, higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products or a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy.

If Sunoco Logistics is unable to replace any significant volume declines with additional volumes from other sources, Sunoco’s financial position, results of operations or cash flows could be materially and adversely affected.

Rate regulation or market conditions may not allow Sunoco Logistics to recover the full amount of increases in the costs of its pipeline operations. A successful challenge to Sunoco Logistics’ pipeline rates could materially and adversely affect Sunoco’s financial condition, results of operations or cash flows.

The primary ratemaking methodology used by the Federal Energy Regulatory Commission, or FERC, to authorize increases in the rates of petroleum pipelines is price indexing. If the changes under the indexing methodology are not large enough to fully reflect actual increases to Sunoco Logistics pipeline costs, its financial condition and Sunoco’s could be adversely affected. If applying the index methodology results in a rate increase that is substantially in excess of the pipeline’s actual cost increases, or it results in a rate decrease that is substantially less than the pipeline’s actual cost decrease, Sunoco Logistics may be required to reduce its pipeline rates. The FERC’s ratemaking methodologies may limit Sunoco Logistics’ ability to set rates based on its costs or may delay the use of rates that reflect increased costs. In addition, if the FERC’s indexing methodology changes, the new methodology could materially and adversely affect Sunoco Logistics’ and Sunoco’s financial condition, results of operations or cash flows.

Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of Sunoco Logistics’ FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order Sunoco Logistics to reduce pipeline rates prospectively and to pay refunds to shippers.

In addition, a state commission could also investigate Sunoco Logistics’ intrastate pipeline rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that such pipeline rates exceeded levels justified by Sunoco Logistics’ costs, the state commission could order a reduction in the rates.

Any reduction in the capability of Sunoco Logistics’ shippers to utilize either its pipelines or interconnecting third-party pipelines could cause a reduction of volumes transported in Sunoco Logistics’ pipelines and through its terminals.

Sunoco and the other users of Sunoco Logistics’ pipelines and terminals are dependent upon those pipelines, as well as connections to third-party pipelines, to receive and deliver crude oil and refined products. Any interruptions or reduction in the capabilities of Sunoco Logistics’ pipelines or these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported in Sunoco Logistics’ pipelines or through its terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to Sunoco Logistics’ existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or through its terminals. Allocation reductions of this nature are not infrequent and are beyond Sunoco Logistics’ control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on Sunoco Logistics’ results of operations, financial position, or cash flows.

 

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Sunoco Logistics does not own all of the land on which its pipelines and terminal facilities are located and Sunoco does not own all of the land on which its direct retail service stations are located, and Sunoco leases certain facilities and equipment, and Sunoco is subject to the possibility of increased costs to retain necessary land use which could disrupt Sunoco’s operations.

Sunoco Logistics does not own all of the land on which certain of its pipelines and terminal facilities are located and Sunoco does not own all of the land on which its retail service stations are located, and, therefore, Sunoco and Sunoco Logistics are subject to the risk of increased costs to maintain necessary land use. Sunoco Logistics obtains the rights to construct and operate certain of its pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. The loss of these rights, through its inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on Sunoco Logistics and Sunoco’s financial condition, results of operations and cash flows. Whether Sunoco Logistics has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline (e.g., crude oil or refined products) and the laws of the particular state. In either case, Sunoco Logistics must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect Sunoco Logistics’ business if it was to lose the right to use or occupy the property on which its pipelines are located. Sunoco also has rental agreements for approximately 29% of the company- or dealer-operated retail service stations where Sunoco currently controls the real estate and Sunoco Logistics has rental agreements for certain logistics facilities. As such, both Sunoco and Sunoco Logistics are subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco are leased from third parties for specific periods. Sunoco’s inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on Sunoco’s results of operations and cash flows.

Sunoco is subject to numerous environmental laws and regulations that require substantial expenditures and affect the way Sunoco operates, which could affect its business, future operating results or financial position in a materially adverse way.

Sunoco is subject to extensive federal, state and local laws and regulations, including those relating to the protection of the environment, waste management, discharge of hazardous materials, and the characteristics and composition of refined products. Certain of these laws and regulations also impose obligations to conduct assessment or remediation efforts at Sunoco’s facilities as well as at formerly owned properties or third-party sites where Sunoco has taken wastes for disposal. Environmental laws and regulations may impose liability on Sunoco for the conduct of third parties, or for actions that complied with applicable requirements when taken, regardless of negligence or fault. Environmental laws and regulations are subject to frequent change, and often become more stringent over time. Of particular significance to Sunoco are:

 

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Greenhouse gas emissions: Through the operation of Sunoco’s refineries and marketing facilities, Sunoco’s operations emit greenhouse gases, or GHG, including carbon dioxide. There are various legislative and regulatory measures to address monitoring, reporting or restriction of GHG emissions that are in various stages of review, discussion or implementation. These include federal and state actions to develop programs for the reduction of GHG emissions as well as proposals that would create a cap and trade system that would require Sunoco to purchase carbon emission allowances for emissions at Sunoco’s manufacturing facilities and emissions caused by the use of the fuels that Sunoco sells. In response to findings that emissions of GHGs present an endangerment to public health and the environment, the United States Environmental Protection Agency, or EPA, has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered Prevention of Significant Deterioration, or PSD, and Title V permit

 

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requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is anticipated that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. These EPA rulemakings could adversely affect Sunoco’s operations and restrict or delay Sunoco’s ability to obtain air permits for new or modified facilities. In addition, the EPA published a final rule in October 2009 requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis beginning in 2011 for emissions occurring after January 1, 2010. Moreover, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as petroleum refineries, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from Sunoco’s equipment and operations could require Sunoco to incur costs to reduce emissions of GHGs associated with Sunoco’s operations or could adversely affect demand for the refined petroleum products that Sunoco produces and markets.

Sunoco is also subject to liabilities resulting from its current and past operations, including legal and administrative proceedings related to product liability, contamination from refining operations, past disposal practices, mercury mining, leaks from pipelines and underground storage tanks, premises-liability claims, allegations of exposures of third parties to toxic substances and general environmental claims. Legacy sites include inactive or formerly owned terminals and other logistics assets, divested retail sites, refineries, mercury mines and chemical plants. Resolving such liabilities may result in the assessment of sanctions requiring the payment of monetary fines and penalties, incurrence of costs to conduct corrective actions or pursue investigatory and remedial activities, payment of damages in settlement of claims and suits, and issuance of injunctive relieve or orders that could limit some or all of Sunoco’s operations and have a material adverse effect on Sunoco’s business or results of operations. Although Sunoco has established financial reserves for its environmental liabilities, ongoing remediation activities may result in the discovery of additional contamination which may increase environmental remediation liabilities. Accordingly, we cannot guarantee that current reserves will be adequate to cover all future liabilities even for currently known contamination.

Compliance with current and future environmental laws and regulations could require Sunoco to make significant expenditures, increasing the overall cost of operating its businesses, including capital costs to construct, maintain and upgrade equipment and facilities. To the extent these expenditures are not ultimately reflected in the prices of Sunoco’s products or services, Sunoco’s operating results would be adversely affected. Sunoco’s failure to comply with these laws and regulations could also result in substantial fines or penalties against Sunoco or orders that could limit Sunoco’s operations and have a material adverse effect on its business or results of operations.

Certain federal and state government regulators have sought compensation from companies like Sunoco for natural resource damages as an adjunct to remediation programs. Because Sunoco is involved in a number of remediation sites, a substantial increase in natural resource damage claims at such remedial sites could result in substantially increased costs to Sunoco.

 

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Sunoco Logistics’ business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that Sunoco Logistics stores and transports.

The petroleum products that Sunoco Logistics stores and transports are sold by its customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce Sunoco Logistics’ throughput volume, require Sunoco Logistics to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in Sunoco Logistics’ pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. Sunoco Logistics may be unable to recover these costs through increased revenues.

In addition, the operations of Sunoco Logistics’ butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect Sunoco Logistics’ ability to market its butane blending services licenses.

Product liability claims and litigation could adversely affect Sunoco’s business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. Failure of Sunoco’s products to meet required specifications could result in product liability claims from Sunoco’s shippers and customers and Sunoco may be required to change or modify its product specifications, which can be costly and time consuming. There can be no assurance that product liability claims against Sunoco would not have a material adverse effect on Sunoco’s business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco is a defendant in numerous lawsuits that allege methyl tertiary butyl ether, or MTBE, contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco. These allegations or other product liability claims against Sunoco could have a material adverse effect on Sunoco’s business or results of operations.

Federal and state legislation and/or regulation could have a significant impact on market conditions and/or adversely affect Sunoco’s business and results of operations.

From time to time, new legislation or regulations are adopted by the federal government and various states or other regulatory bodies. Any such federal or state legislation or regulations, including but not limited to any potential environmental rules and regulations, tax legislation, energy policy legislation or legislation affecting trade or commercial practices, could have a significant impact on market conditions and could adversely affect Sunoco’s business or results of operations in a material way. For example, certain pending legislative and regulatory proposals effectively could limit, or even eliminate, use of the last-in, first-out, or LIFO, inventory method for financial and income tax purposes. Although the final outcome of these proposals cannot be ascertained at this time, the ultimate impact to Sunoco of the transition from LIFO to another inventory method could be material. However, Sunoco’s pending exit from the refining business should significantly reduce its exposure to this issue.

 

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Disputes under long-term contracts could affect Sunoco’s business and future operations in a materially adverse way.

Sunoco has numerous long-term contractual arrangements across Sunoco’s businesses that frequently include complex provisions. Interpretation of these provisions may, at times, lead to disputes with customers and/or suppliers. Unfavorable resolutions of these disputes could have a significant adverse effect on Sunoco’s business and results of operations.

Competition from companies having greater financial and other resources than Sunoco does could materially and adversely affect Sunoco’s business and results of operations.

Sunoco competes with domestic refiners and marketers in the northeastern and midwestern United States and with foreign refiners that import products into the United States. In addition, Sunoco competes with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of Sunoco’s industrial, commercial and individual consumers. Certain of Sunoco’s competitors have larger and more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of Sunoco’s principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than Sunoco does. Unlike these competitors, which have access to proprietary sources of controlled crude oil production, Sunoco obtains substantially all of its feedstocks from unaffiliated sources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil and other feedstocks or intense price fluctuations.

Sunoco has taken significant measures to expand and upgrade units in its refineries by installing new equipment and redesigning older equipment to improve refinery capacity. However, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment, or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition. Newer facilities owned by competitors will often be more efficient than some of Sunoco’s facilities, which may put Sunoco at a competitive disadvantage. Over time, some of Sunoco’s facilities may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities.

Sunoco also faces strong competition in the market for the sale of retail gasoline and merchandise. Sunoco’s competitors include service stations operated by fully integrated major oil companies and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at aggressively competitive prices.

Pipeline operations of Sunoco Logistics face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Sunoco Logistics’ refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

The actions of Sunoco’s competitors, including the impact of foreign imports, could lead to lower prices or reduced margins for the products Sunoco sells, which could have an adverse effect on Sunoco’s business or results of operations.

 

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Sunoco is exposed to the credit and other counterparty risk of its customers in the ordinary course of its business.

Sunoco has various credit terms with virtually all of its customers, and its customers have varying degrees of creditworthiness. Although Sunoco evaluates the creditworthiness of each of its customers, Sunoco may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose Sunoco to an increased risk of nonpayment or other default under its contracts and other arrangements with them. In the event that a material customer or customers default on their payment obligations to Sunoco, this could materially adversely affect Sunoco’s financial condition, results of operations or cash flows.

Sunoco maintains insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that it believes to be prudent. Failure by one or more insurers to honor their coverage commitments for an insured event could materially and adversely affect Sunoco’s future cash flows, operating results and financial condition.

Sunoco’s business is subject to hazards and risks inherent in refining operations and the transportation and storage of crude oil and refined products. These risks include explosions, fires, spills, adverse weather, natural disasters, mechanical failures, security breaches at Sunoco’s facilities, labor disputes and maritime accidents, any of which could result in loss of life or equipment, business interruptions, environmental pollution, personal injury and damage to Sunoco’s property and that of others. In addition, certain of Sunoco’s facilities provide or share necessary resources, materials or utilities, rely on common resources or utilities for their supply, distribution or materials or are located in close proximity to other of Sunoco’s facilities. As a result, an event, such as the closure of a transportation route, could adversely affect more than one facility. Sunoco’s refineries, pipelines and storage facilities also may be potential targets for terrorist attacks.

Sunoco maintains insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that Sunoco believes to be prudent. Sunoco’s insurance program includes a number of insurance carriers. Disruptions in the U.S. financial markets have resulted in the deterioration in the financial condition of many financial institutions, including insurance companies. In light of this uncertainty, it is possible that Sunoco may not be able to obtain insurance coverage for insured events. Sunoco’s failure to do so could have a material adverse effect on its future cash flows, operating results and financial condition.

Sunoco’s operating facilities, and in particular its refineries, require substantial capital expenditures to maintain their reliability and efficiency. If Sunoco is unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in Sunoco’s project economics deteriorate, Sunoco’s financial condition, results of operations or cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving engineering, procurement and construction of new facilities (or improvements and repairs to Sunoco’s existing facilities) could adversely affect Sunoco’s ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to Sunoco’s facilities could subject us to fines or penalties as well as affect Sunoco’s ability to supply certain products Sunoco makes. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond Sunoco’s control, including:

 

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denial or delay in issuing regulatory approvals and/or permits;

 

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unplanned increases in the cost of construction materials or labor;

 

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disruptions in transportation of modular components and/or construction materials;

 

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severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting Sunoco’s facilities, or those of vendors and suppliers;

 

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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

 

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•

market-related increases in a project’s debt or equity financing costs; and/or

 

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nonperformance or force majeure by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.

Sunoco’s refineries consist of many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures to keep it operating at optimum efficiency. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that are more frequent than Sunoco’s scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce Sunoco’s revenues during the period of time that the units are not operating. The need for significant future capital spending to maintain Sunoco’s refineries may have a material adverse impact on the likelihood of Sunoco’s successful completion of a sale of its refining assets and the ultimate value which may be realized upon such sale.

Sunoco’s forecasted internal rates of return are also based upon Sunoco’s projections of future market fundamentals that are not within Sunoco’s control, including changes in general economic conditions, available alternative supply and customer demand.

Any one or more of these factors could have a significant impact on Sunoco’s business. If Sunoco was unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect Sunoco’s financial position, results of operations or cash flows.

Sunoco has various credit agreements and other financing arrangements that impose certain restrictions on Sunoco and may limit Sunoco’s flexibility to undertake certain types of transactions. If Sunoco fails to comply with the terms and provisions of its debt instruments, the indebtedness under them may become immediately due and payable, which could have a material adverse effect on Sunoco’s financial position.

Several of Sunoco’s existing debt instruments and financing arrangements contain restrictive covenants and that limit Sunoco’s financial flexibility and that of its subsidiaries. Sunoco’s credit facilities require the maintenance of collateral and certain financial ratios, satisfaction of certain financial condition tests and, subject to certain exceptions, impose restrictions on:

 

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incurrence of additional indebtedness;

 

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issuance of preferred stock by Sunoco’s subsidiaries;

 

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incurrence of liens;

 

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sale and leaseback transactions;

 

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agreements by Sunoco’s subsidiaries, which would limit their ability to pay dividends, make distributions or repay loans or advances to Sunoco; and

 

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fundamental changes, such as certain mergers and dispositions of assets.

Sunoco Logistics has credit facilities which also contain certain covenants. Increased borrowings by Sunoco Logistics will raise the level of Sunoco’s total consolidated net indebtedness, and could restrict Sunoco’s ability to borrow money or otherwise incur additional debt. If Sunoco does not comply with the covenants and other terms and provisions of its credit facilities, Sunoco will be required to request a waiver under, or an amendment to, those facilities. If Sunoco cannot obtain such a waiver or amendment, or if Sunoco fails to comply with the covenants and other terms and provisions of Sunoco’s indentures, Sunoco would be in default under its debt instruments. Any defaults may cause the indebtedness under the facilities to become immediately due and payable, which could have a material adverse effect on Sunoco’s financial position.

Sunoco’s ability to meet its debt service obligations depends upon its future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting its operations,

 

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many of which are beyond Sunoco’s control. A portion of Sunoco’s cash flow from operations is needed to pay the principal of, and interest on, Sunoco’s indebtedness and is not available for other purposes. If Sunoco is unable to generate sufficient cash flow from operations, Sunoco may have to sell assets, refinance all or a portion of its indebtedness or obtain additional financing. Any of these actions could have a material adverse effect on Sunoco’s financial position.

The tax treatment of Sunoco Logistics depends on its status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity level taxation by individual states. If the IRS treats Sunoco Logistics as a corporation or it becomes 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 its unitholders.

The anticipated after-tax economic benefit of our investment in the common units of Sunoco Logistics depends largely on Sunoco Logistics being treated as a partnership for federal income tax purposes. Sunoco Logistics has not requested, and does not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones Sunoco Logistics has taken. A successful IRS contest of the federal income tax positions Sunoco Logistics takes may impact adversely the market for its common units, and the costs of any IRS contest will reduce Sunoco Logistics’ cash available for distribution to its unitholders. If Sunoco Logistics was treated as a corporation for federal income tax purposes, it would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to its unitholders generally would be subject to tax again as corporate distributions. Treatment of Sunoco Logistics as a corporation would result in a material reduction in its anticipated cash flow and after-tax return to its unitholders. Current law may change so as to cause Sunoco Logistics to be treated as a corporation for federal income tax purposes or to otherwise subject it to a material level of entity level taxation. 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 of these states were to impose a tax on Sunoco Logistics, the cash available for distribution to its unitholders would be reduced.

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

The present federal income tax treatment of publicly traded partnerships, including Sunoco Logistics, or our investment in its common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for Sunoco Logistics to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause Sunoco Logistics to change its business activities, or affect the tax consequences of our investment in Sunoco Logistics’ common units. For example, members of the United States Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from partnerships. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of our investment in Sunoco Logistics’ common units.

Poor performance in the financial markets could have a material adverse effect on the level of funding of Sunoco’s pension obligations, on the level of pension expense and on Sunoco’s financial position. In addition, any use of current cash flow to fund Sunoco’s pension could have a significant adverse effect on Sunoco’s financial position.

Sunoco has substantial benefit obligations in connection with its noncontributory defined benefit pension plans. Sunoco has made contributions to the plans over the past several years to improve their funded status, and Sunoco expects to make additional contributions to the plans in the future as well. The projected benefit obligation of Sunoco’s funded defined benefit plans at December 31, 2011 exceeded the market value of

 

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Sunoco’s plan assets by $160 million. Sunoco expects that upon its exit from the refining business, defined benefit pension plans will be frozen for all participants and no additional benefits will be earned. As a result of the workforce reduction, divestments and the shutdown of Sunoco’s Eagle Point refinery, Sunoco incurred noncash settlement and curtailment losses and special termination benefits in these plans during 2011, 2010 and 2009 totaling approximately $60 million, $55 million and $130 million pretax, respectively. Sunoco expects to incur additional settlement losses related to the exit from the refining business. In 2010, Sunoco contributed $234 million to its funded defined benefit plans consisting of $144 million of cash and 3.59 million shares of Sunoco common stock valued at $90 million. Sunoco also intends to make cash contributions of approximately $80 million in 2012. Poor performance of the financial markets, or decreases in interest rates, could result in additional significant charges to shareholders’ equity and additional significant increases in future pension expense and funding requirements. To the extent that Sunoco has to fund its pension obligations with cash from operations, Sunoco may be at a disadvantage to some of its competitors who do not have the same level of obligations that Sunoco has.

A portion of Sunoco’s workforce is unionized, and Sunoco may face labor disruptions that could materially and adversely affect its operations.

Approximately 18% of Sunoco’s employees are covered by a number of collective bargaining agreements with various terms and dates of expirations. There can be no assurances that Sunoco will not experience a work stoppage in the future as a result of labor disagreements. A labor disturbance at any of Sunoco’s major facilities could have a material adverse effect on Sunoco’s operations.

Sunoco has outsourced various functions to third-party service providers, which decreases its control over the performance of these functions. Disruptions or delays at Sunoco’s third-party outsourcing partners could result in increased costs, or may adversely affect service levels and Sunoco’s public reporting. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose Sunoco to additional liability.

As part of Sunoco’s long-term strategy, Sunoco is continually looking for opportunities to provide essential business services in a more cost-effective manner. In some cases, this requires the outsourcing of functions or parts of functions that can be performed more effectively by external service providers. Sunoco has previously outsourced various functions to third parties and expect to continue this practice with other functions in the future.

While outsourcing arrangements may lower Sunoco’s cost of operations, they also reduce Sunoco’s direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on Sunoco’s ability to quickly respond to changing market conditions, or on Sunoco’s ability to ensure compliance with all applicable domestic and foreign laws and regulations. Sunoco believes that it conducts appropriate due diligence before entering into agreements with its outsourcing partners. Sunoco relies on its outsourcing partners to provide services on a timely and effective basis. Although Sunoco continuously monitors the performance of these third parties and maintains contingency plans in case they are unable to perform as agreed, Sunoco does not ultimately control the performance of its outsourcing partners. Much of Sunoco’s outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of Sunoco’s third-party outsourcing partners to provide the expected services on a timely basis at the prices Sunoco expects, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to Sunoco’s operations, which could materially adversely affect Sunoco’s business, financial condition, operating results and cash flow and Sunoco’s ability to file its financial statements with the SEC in a timely or accurate manner.

 

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Sunoco’s failure to generate significant cost savings from these outsourcing initiatives could adversely affect its profitability and weaken its competitive position. Additionally, if the implementation of Sunoco’s outsourcing initiatives is disruptive to its business, Sunoco could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause its business and results of operations to suffer.

As a result of these outsourcing initiatives, more third parties are involved in processing Sunoco’s information and data. Breaches of Sunoco’s security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about Sunoco or its clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose Sunoco to a risk of loss or misuse of this information, result in litigation and potential liability for Sunoco, lead to reputational damage to Sunoco brand, increase Sunoco’s compliance costs, or otherwise harm Sunoco’s business.

Sunoco’s operations could be disrupted if Sunoco’s information systems fail, causing increased expenses and loss of sales.

Sunoco’s business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including its enterprise resource planning tools. Sunoco processes a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, Sunoco’s operations and financial results could be affected adversely. Sunoco’s systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. Sunoco has a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Sunoco’s business interruption insurance may not compensate it adequately for losses that may occur.

Security breaches and other disruptions could compromise Sunoco Logistics’ information and expose Sunoco Logistics to liability, which would cause its business and reputation to suffer.

In the ordinary course of Sunoco Logistics’ business, Sunoco Logistics collects and stores sensitive data, including intellectual property, its proprietary business information and that of its customers, suppliers and business partners, and personally identifiable information of its employees, in Sunoco Logistics’ data centers and on its networks. The secure processing, maintenance and transmission of this information is critical to Sunoco Logistics’ operations and business strategy. Despite Sunoco Logistics’ security measures, its information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise Sunoco Logistics’ networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of Sunoco Logistics’ operations, damage to its reputation, and loss of confidence in its products and services, which could adversely affect its business.

Tax Risks to Common Unitholders

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

 

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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.

The present tax treatment of publicly traded partnerships, including us, or an investment in our Common Units, may be modified by administrative, legislative or judicial interpretation at any time, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, recently, members of the U.S. Congress considered substantive changes to the existing U.S. federal income tax laws that would have affected the tax treatment of certain publicly traded 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. Any modification to the U.S. federal income or state tax laws, or interpretations thereof, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals 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 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 your 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,

 

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in some cases, state and local income taxes on your share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from the taxation of your 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. Please read “Material Income Tax Consideration — Disposition of Common Units — Recognition of Gain or Loss” for further discussion of the foregoing.

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

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (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 your share of our taxable income.

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

Certain of our business activities and operations are conducted through subsidiaries treated as corporations for U.S. federal income tax purposes, including the activities of Citrus Corp, Heritage Holdings, Inc. and Oasis Pipe Line Company. In the future, we may conduct additional operations through these subsidiaries or additional subsidiaries that are subject to corporate-level income taxes. The taxable income, if any, of subsidiaries that are treated as corporations for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced.

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.

 

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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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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.

 

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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 federal partnership tax returns 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 on the technical termination date, 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.

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, either directly or indirectly as a result of our investment in AmeriGas. 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.

 

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USE OF PROCEEDS

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

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

 

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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,				Four Months Ended December 31, 2007(1)				Year Ended December 31,																Six Months Ended June 30,
		2007								2008				2009				2010				2011				2012
Ratio of earnings to fixed charges			4.28				4.31				3.95				2.92				2.31				2.39				4.11

 

(1)	In November 2007, we changed our fiscal year end from a year ending August 31 to a year ending December 31. Accordingly, the four months ended December 31, 2007 is treated as a transition period.

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

 

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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.

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

 

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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.

 

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DESCRIPTION OF UNITS

As of September 18, 2012, there were approximately 350,000 individual common unitholders, which includes common units held in street name. Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in our Second Amended and Restated Agreement of Limited Partnership.

Common Units, Class E Units, Class F Units and General Partner Interest

As of September 18, 2012, we had 245,561,561 common units outstanding, of which 193,085,502 were held by the public, including approximately 586,000 common units held by our officers and directors, and 52,476,059 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 owned by Heritage Holdings. The Class E units generally do not have any voting rights. These Class E units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all unitholders, including the Class E unitholders, up to $1.41 per unit per year. Although no plans are currently in place, management may evaluate whether to retire some or all of the Class E units at a future date.

In conjunction with the Sunoco merger, we will amend our partnership agreement to create the Class F units. The number of Class F units to be issued will be determined at the closing of the merger and will equal 50,706,00 Class F units, plus an amount equal to the amount of cash contributed by Sunoco to us immediately prior to or concurrent with the closing of the Sunoco merger divided by $50.00. The Class F units generally will not have any voting rights. The Class F units to be issued to Sunoco in connection with the Sunoco merger will be entitled to aggregate cash distributions equal to 35% of the total amount of cash that is generated by us and our subsidiaries (other than Holdco) and available for distribution, up to a maximum of $3.75 per Class F unit per year.

As of September 18, 2012, our general partner owned an approximate 1.4% general partner interest in us and the holders of common units and Class E units collectively owned an approximate 98.6% limited partner interest in us.

Issuance of Additional Securities

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

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

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

Upon issuance of additional partnership securities, our general partner has the right to make additional capital contributions to the extent necessary to maintain its then-existing general partner interest in us. In the

 

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

Unitholder Approval

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

 

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a merger of our partnership;

 

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a sale or exchange of all or substantially all of our assets;

 

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dissolution or reconstitution of our partnership upon dissolution;

 

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certain amendments to the partnership agreement; and

 

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the transfer to another person of the incentive distribution rights at any time, except for transfers to affiliates of the general partner or transfers in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person.

The removal of our general partner requires the approval of not less than 66 2/3% of all outstanding units, including units held by our general partner and its affiliates. Any removal is subject to the election of a successor general partner by the holders of a majority of the outstanding common units, including units held by our general partner and its affiliates.

Amendments to Our Partnership Agreement

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

 

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a change in our name, the location of our principal place of business or our registered agent or office;

 

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the admission, substitution, withdrawal or removal of partners;

 

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a change to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability or to ensure that neither we nor our operating partnership will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

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a change that does not adversely affect our unitholders in any material respect;

 

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a change (i) that is necessary or advisable to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, or (B) facilitate the trading of common units or comply with any rule, regulation, guideline or requirement of any national securities exchange on which the common units are or will be listed for trading, (ii) that is necessary or advisable in connection with action taken by our general partner with respect to subdivision and combination of our securities or (iii) that is required to effect the intent expressed in our partnership agreement;

 

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a change in our fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in our fiscal year or taxable year;

 

•

an amendment that is necessary to prevent us, or our general partner or its directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisors Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended;

 

•

an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of our securities;

 

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

•

an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with our partnership agreement;

 

•

an amendment that is necessary or advisable to reflect, account for and deal with appropriately our formation of, or investment in, any corporation, partnership, joint venture, limited liability company or other entity other than our operating partnership, in connection with our conduct of activities permitted by our partnership agreement;

 

•

a merger or conveyance to effect a change in our legal form; or

 

•

any other amendment substantially similar to the foregoing.

Withdrawal or Removal of Our General Partner

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

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

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% 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

 

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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.

Liquidation and Distribution of Proceeds

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

 

•

first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

 

•

then, to all partners in accordance with the positive balance in their respective capital accounts.

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

Limited Call Right

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.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify our general partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest 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.

Listing

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

Transfer Agent and Registrar

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

 

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Transfer of Common Units

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

 

•

becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

 

•

automatically requests admission as a substituted limited partner in our partnership;

 

•

agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

 

•

represents that such person has the capacity, power and authority to enter into the partnership agreement;

 

•

grants to our general partner the power of attorney to execute and file documents required for our existence and qualification as a limited partnership, the amendment of the partnership agreement, our dissolution and liquidation, the admission, withdrawal, removal or substitution of partners, the issuance of additional partnership securities and any merger or consolidation of the partnership; and

 

•

makes the consents and waivers contained in the partnership agreement, including the waiver of the fiduciary duties of the general partner to unitholders as described in “Risk Factors — Risks Related to Conflicts of Interests — 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” included in our Annual Report on Form 10-K for the year ended December 31, 2011.

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:

 

•

the right to assign the common unit to a purchaser or transferee; and

 

•

the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units.

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

 

•

will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

 

•

may not receive some federal income tax information or reports furnished to record holders of common units.

 

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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.

Status as Limited Partner or Assignee

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

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act, 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 more than 40 states. To maintain the limited liability of our limited partners, we may be required to comply with legal requirements in the jurisdictions in which our subsidiaries conduct 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 any of our subsidiaries were conducting business in any state without compliance with the applicable limited partnership statute, or that our rights with respect to any such subsidiary constituted “participation in the control” of any such subsidiary’s business for purposes of the statutes of any relevant jurisdiction, then we could be held personally liable for such subsidiary’s obligations under the law of that jurisdiction.

 

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Meetings; Voting

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

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. 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.

Books and Reports

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

We will furnish or make available to record holders of common units, within 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.

 

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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:

 

•

a current list of the name and last known address of each partner;

 

•

a copy of our tax returns;

 

•

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

 

•

copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

 

•

information regarding the status of our business and financial condition; and

 

•

any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets 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.

 

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CASH DISTRIBUTION POLICY

Following is a description of the relative rights and preferences of holders of our common units in and to cash distributions. The information presented in this section assumes that our general partner continues to make capital contributions to us in order to maintain its 1.4% general partner interest.

Distributions of Available Cash

General. We will distribute all of our “available cash” to our unitholders and our general partner within 45 days following the end of each fiscal quarter.

Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:

 

•

less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law or any debt instrument or other agreement (including reserves for future capital expenditures and for our future credit needs); or

 

•

provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters;

 

•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases are used solely for working capital purposes or to pay distributions to partners.

Operating Surplus and Capital Surplus

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

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

 

•

our cash balance on the closing date of our initial public offering; plus

 

•

$10.0 million (as described below); plus

 

•

all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

 

•

our working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

 

•

all of our operating expenditures after the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

 

•

the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

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

 

•

borrowings other than working capital borrowings;

 

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•

sales of debt and equity securities; and

 

•

sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

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

Incentive Distribution Rights

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

Distributions of Available Cash from Operating Surplus

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:

 

•

First, 100% to all common unitholders, Class E unitholders, Class F unitholders (when and if issued) and the general partner, in accordance with their percentage interests, until each common unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”);

 

•

Second, 100% to all common unitholders, Class E unitholders, Class F unitholders (when and if issued) and the general partner, in accordance with their respective percentage interests, until each common unit has received $0.275 per unit for such quarter (the “first target distribution”);

 

•

Third, 87% to all common unitholders, Class E unitholders, Class F unitholders (when and if issued) and the general partner, in accordance with their respective percentage interests, and 13% to the holders of incentive distribution rights, pro rata, until each common unit has received $0.3175 per unit for such quarter (the “second target distribution”);

 

•

Fourth, 77% to all common unitholders, Class E unitholders, Class F unitholders (when and if issued) and the general partner, in accordance with their respective percentage interests, and 23% to the holders of incentive distribution rights, pro rata, until each common unit has received $0.4125 per unit for such quarter (the “third target distribution”); and

 

•

Fifth, thereafter, 52% to all common unitholders, Class E unitholders, Class F unitholders (when and if issued) and the general partner, in accordance with their respective percentage interests, and 48% to the holders of incentive distribution rights, pro rata.

Notwithstanding the foregoing, the distributions on each Class E unit may not exceed $1.41 per year and distributions on each Class F unit (when and if issued) may not exceed $3.75 per year. In addition, the distributions to the holders of the incentive distribution rights will not exceed the amount the holders of the

 

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incentive distributions rights would otherwise receive if the available cash for distribution were reduced to the extent it constitutes amounts previously distributed with respect to the Class F units.

Distributions of Available Cash from Capital Surplus

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:

 

•

First, 100% to all unitholders and the general partner, in accordance with their respective percentage interests, until we distribute for each common unit an amount of available cash from capital surplus equal to the initial public offering price;

 

•

Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

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.

Distributions of Cash Upon Liquidation

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

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

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

 

•

First, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

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•

Second, 100% to the Class F unitholders until the capital account for each Class F unit is equal to its original issue price;

 

•

Third, 100% to the common unitholders and the general partner, in accordance with their respective percentage interests, until the capital account for each common unit is equal to the sum of:

 

•

the unrecovered capital; and

 

•

the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

•

Fourth, 1% to the Class E unitholders and 1% to the Class F unitholders, with the remainder being allocated 100% to the common unitholders and the general partner, in accordance with their respective percentage interests, until we allocate under this paragraph an amount per unit equal to:

 

•

the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

 

•

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 100% to the unitholders and the general partner, in accordance with their percentage interests, for each quarter of our existence;

 

•

Fifth, 87% to the common unitholders and the general partner, in accordance with their respective percentage interests, and 13% to the holders of the incentive distribution rights, pro rata, until we allocate under this paragraph an amount per unit equal to:

 

•

the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

 

•

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 87% to the unitholders and the general partner, in accordance with their percentage interests, and 13% to the holders of the incentive distribution rights, pro rata, for each quarter of our existence;

 

•

Sixth, 77% to the common unitholders and the general partner, in accordance with their respective percentage interests, and 23% to the holders of the incentive distribution rights, pro rata, until we allocate under this paragraph an amount per unit equal to:

 

•

the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

 

•

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 77% to the unitholders and the general partner, in accordance with their respective percentage interests, and 23% to the holders of the incentive distribution rights, pro rata, for each quarter of our existence; and

 

•

Seventh, thereafter, 52% to the common unitholders and the general partner, in accordance with their respective percentage interests, and 48% to the holders of the incentive distribution rights, pro rata.

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:

 

•

First, 100% to the common unit holders, the Class E unitholders, the Class F unitholders and the general partner in proportion to the positive balances in the common unitholders’ capital accounts and the general partner’s percentage interest, respectively, until the capital accounts of the common unitholders, the Class E unitholders and the Class F unitholders have been reduced to zero; and

 

•

Second, thereafter, 100% to the general partner.

 

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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.

 

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DESCRIPTION OF THE DEBT SECURITIES

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

Provisions Applicable to the Indenture

General. Any series of debt securities will be our general obligation.

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:

 

•

the form and title of the debt securities of that series;

 

•

the total principal amount of the debt securities of that series;

 

•

whether the debt securities will be issued in individual certificates to each holder or in the form of temporary or permanent global securities held by a depositary on behalf of holders;

 

•

the date or dates on which the principal of and any premium on the debt securities of that series will be payable;

 

•

any interest rate which the debt securities of that series will bear, the date from which interest will accrue, interest payment dates and record dates for interest payments;

 

•

any right to extend or defer the interest payment periods and the duration of the extension;

 

•

whether and under what circumstances any additional amounts with respect to the debt securities will be payable;

 

•

the place or places where payments on the debt securities of that series will be payable;

 

•

any provisions for optional redemption or early repayment;

 

•

any provisions that would require the redemption, purchase or repayment of debt securities;

 

•

the denominations in which the debt securities will be issued;

 

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•

whether payments on the debt securities will be payable in foreign currency or currency units or another form and whether payments will be payable by reference to any index or formula;

 

•

the portion of the principal amount of debt securities that will be payable if the maturity is accelerated, if other than the entire principal amount;

 

•

any additional means of defeasance of the debt securities, any additional conditions or limitations to defeasance of the debt securities or any changes to those conditions or limitations;

 

•

any changes or additions to the events of default or covenants described in this prospectus;

 

•

any restrictions or other provisions relating to the transfer or exchange of debt securities;

 

•

any terms for the conversion or exchange of the debt securities for our other securities or securities of any other entity; and

 

•

any other terms of the debt securities of that series.

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.

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:

 

•

failure to pay interest on that series of debt securities for 30 days when due;

 

•

default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;

 

•

default in the payment of any sinking fund payment on any debt securities of that series when due;

 

•

failure by us to comply with the other agreements contained in the indenture, any supplement to the indenture or any board resolution authorizing the issuance of that series for 60 days after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding debt securities issued under the indenture that are affected by that failure;

 

•

certain events of bankruptcy, insolvency or reorganization of us; and

 

•

any other event of default provided for with respect to that 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

 

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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:

 

•

the holder gives the trustee written notice of a continuing event of default for that series;

 

•

the holders of at least 25% in principal amount of the outstanding debt securities of that series make a written request to the trustee to pursue the remedy;

 

•

the holders offer to the trustee security or indemnity satisfactory to the trustee;

 

•

the trustee fails to act for a period of 60 days after receipt of the request and offer of security or indemnity; and

 

•

during that 60-day period, the holders of a majority in principal amount of the debt securities of that series do not give the trustee a direction inconsistent with the request.

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:

 

•

conducting any proceeding for any remedy available to the trustee; and

 

•

exercising any trust or power conferred upon the trustee relating to or arising as a result of an event of default.

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:

 

•

reduce the percentage in principal amount of debt securities whose holders must consent to an amendment, a supplement or a waiver;

 

•

reduce the rate of or extend the time for payment of interest on the debt security;

 

•

reduce the principal of, or any premium on, the debt security or change its stated maturity;

 

•

reduce any premium payable on the redemption of the debt security or change the time at which the debt security may or must be redeemed;

 

•

change any obligation to pay additional amounts on the debt security;

 

•

make payments on the debt security payable in currency other than as originally stated in the debt security;

 

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•

impair the holder’s right to receive payment of principal of and premium, if any, and interest on or any additional amounts with respect to such holder’s debt securities or to institute suit for the enforcement of any payment on or with respect to the debt security;

 

•

make any change in the percentage of principal amount of debt securities necessary to waive compliance with certain provisions of the indenture or to make any change in the provision related to modification;

 

•

waive a continuing default or event of default regarding any payment on the debt securities; or

 

•

except as provided in the indenture, release any security that may have been granted in respect of any debt securities.

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:

 

•

to cure any ambiguity, omission, defect or inconsistency;

 

•

to provide for the assumption of our obligations under the indenture by a successor upon any merger, consolidation or asset transfer permitted under the indenture;

 

•

to provide for uncertificated debt securities in addition to or in place of certificated debt securities or to provide for bearer debt securities;

 

•

to provide any security for or any additional obligors on any series of debt securities;

 

•

to comply with any requirement to effect or maintain the qualification of the indenture under the Trust Indenture Act;

 

•

to add covenants that would benefit the holders of any debt securities or to surrender any rights we have under the indenture;

 

•

to add events of default with respect to any debt securities; and

 

•

to make any change that does not adversely affect any outstanding debt securities of any series 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:

 

•

we will be discharged from our or their obligations with respect to the debt securities of that series (“legal defeasance”); or

 

•

we will no longer have any obligation to comply with the restrictive covenants, the merger covenant and other specified covenants under the indenture, and the related events of default will no longer apply (“covenant defeasance”).

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 will also survive.

 

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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. under the debt securities or the indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. By accepting a debt security, each holder of that debt security will have agreed to this provision and waived and released any such liability on the part of our general partner and its directors, officers, employees, incorporators and partners. This waiver and release are part of the consideration for our issuance of the debt securities. It is the view of the SEC that a waiver of liabilities under the federal securities laws is against public policy and unenforceable.

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

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

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

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

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

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

 

•

any debt security during a period beginning 15 business days prior to the mailing of the relevant notice of redemption and ending on the close of business on the day of mailing of such notice; or

 

•

any debt security that has been called for redemption in whole or in part, except the unredeemed portion of any debt security being redeemed in part.

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.

 

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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.

 

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MATERIAL INCOME TAX CONSIDERATIONS

This section is a summary of the material U.S. federal income tax consequences that may be relevant to prospective holders of ETP common units who are individual citizens or residents of the United States. Unless otherwise noted in the following discussion, this section is the opinion of Vinson & Elkins L.L.P., counsel to ETP’s general partner and ETP, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law.

The following discussion does not address all federal income tax matters affecting ETP or its unitholders. Moreover, this discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt organizations, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and foreign persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Internal Revenue Code. In addition, this discussion only comments, to a limited extent, on state, local, and foreign tax consequences. Prospective unitholders are strongly encouraged to consult their tax advisors in analyzing the state, local, foreign and other tax consequences particular to them of the ownership or disposition of ETP common units.

No ruling has been or is expected to be requested from the IRS regarding any matter affecting ETP or prospective unitholders. Instead, ETP expects to rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements expressed 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 ETP common units and the prices at which ETP 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 ETP unitholders and ETP’s general partner and thus will be borne indirectly by ETP unitholders and ETP’s general partner. Furthermore, the tax treatment of ETP, or of an investment in ETP, 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 Vinson & Elkins L.L.P. It must be emphasized that this opinion is based on various assumptions and representations as to factual matters (please read “— Partnership Status”), including representations made by ETP in a factual certificate provided by one of ETP’s officers. In addition, this opinion is based upon ETP’s factual representations set forth in this document.

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

 

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Partnership Status

For U.S. federal income tax purposes, a partnership is not a taxable entity and incurs no U.S. 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 U.S. 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 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 herein 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.” ETP’s qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof, the retail and wholesale marketing of propane, the transportation of propane and natural gas liquids, and certain related hedging activities. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. ETP estimates that less than 4% of its 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 ETP and its general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of ETP’s current gross income constitutes qualifying income. The portion of ETP’s income that is qualifying income may change from time to time.

No ruling has been or is expected to be sought from the IRS and the IRS has made no determination as to ETP’s status for U.S. federal income tax purposes. Instead, ETP will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, Revenue Rulings published by the IRS, court decisions and the representations described below that ETP will be classified as a partnership for U.S. federal income tax purposes.

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

 

•

ETP has not elected and will not elect to be treated as a corporation;

 

•

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

 

•

each hedging transaction that ETP treats as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by ETP or its subsidiaries in activities of the type that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income; and that

 

•

no amount of interest received by ETP or its subsidiaries has been (i) derived in the conduct of a financial or insurance business, or (ii) determined or based, in whole or in part, on the net income or profits of any person.

ETP believes that these representations have been true in the past and expects that these representations will continue to be true in the future.

If ETP fails 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

 

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ETP to make adjustments with respect to ETP unitholders or pay other amounts), ETP will be treated as if ETP had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which ETP fails 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 ETP. This deemed contribution and liquidation should be tax-free to unitholders and ETP so long as ETP, at that time, does not have liabilities in excess of the tax basis of its assets. Thereafter, ETP would be treated as a taxable C-corporation for U.S. federal income tax purposes.

If ETP was taxed as a C-corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, ETP’s items of income, gain, loss and deduction would be reflected only on ETP’s tax return rather than being passed through to ETP’s unitholders, and ETP’s net income would be taxed to ETP at corporate rates. If ETP was taxable as a corporation, losses recognized by ETP would not flow through to ETP’s unitholders. In addition, any distribution made by ETP to a unitholder would be treated as taxable dividend income, to the extent of ETP’s 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 ETP common units, or taxable capital gain, after the unitholder’s tax basis in his ETP common units is reduced to zero. Accordingly, taxation of ETP as a C-corporation would result in a material reduction in a unitholder’s cash flow and after-tax return attributable to ETP’s common units, and thus would likely result in a substantial reduction of the value of the units.

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

Limited Partner Status

Holders of ETP common units will be treated as partners of ETP for U.S. federal income tax purposes. Holders of ETP common units include assignees who have executed and delivered transfer applications and are awaiting admission as limited partners and unitholders whose ETP common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their ETP common units will be treated as partners of ETP for U.S. federal income tax purposes. However, as there is no direct or indirect controlling authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of ETP 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 ETP 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 ETP 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 U.S. federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales” below.

Income, gains, deductions or losses would not appear to be reportable by a unitholder who is not a partner for U.S. federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for U.S. federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding ETP common units. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in ETP for U.S. federal income tax purposes.

 

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Entity-Level Taxation

Even though ETP (as a partnership for U.S. federal income tax purposes) generally is not subject to U.S. federal income tax, certain of ETP’s business activities and operations are conducted through subsidiaries treated as corporations for U.S. federal income tax purposes, including the activities of Citrus Corp, Heritage Holdings, Inc. and Oasis Pipeline Company. The taxable income, if any, of subsidiaries that are treated as corporations for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes, which may reduce the cash available for distribution to ETP and, in turn, to ETP’s unitholders. In the future, ETP may conduct additional operations through these subsidiaries or additional subsidiaries that are subject to corporate-level income taxes. Moreover, some of ETP’s subsidiaries and operations may be subject to income and other taxes in the jurisdictions in which they are organized or from which they receive income. Such taxation will reduce the amount of cash ETP has available for distribution to its unitholders.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussions under “Taxation of the Partnership — Entity-Level Taxation” above and “— Entity-Level Collections” below, ETP will not pay any U.S. federal income tax. Instead, each unitholder will be required to report on his income tax return his share of ETP’s income, gains, losses and deductions without regard to whether ETP makes cash distributions to him. Consequently, ETP 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 ETP’s income, gains, losses and deductions for ETP’s taxable year ending with or within his taxable year. ETP’s taxable year ends on December 31.

Treatment of Distributions

Distributions by ETP to a unitholder generally will not be taxable to the unitholder for U.S. federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his ETP common units immediately before the distribution. ETP’s cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the ETP common units, taxable in accordance with the rules described under “— Disposition of ETP Common Units” below. Any reduction in a unitholder’s share of ETP’s 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 by ETP of cash to that unitholder. To the extent ETP’s 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 ETP because of its issuance of additional ETP common units will decrease his share of ETP’s 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 ETP common units, if the distribution reduces the unitholder’s share of ETP’s “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with ETP 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 (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

 

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Basis of ETP Common Units

A unitholder’s tax basis in his ETP common units initially will be the amount paid for those units plus his share of ETP’s nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss). That basis will be increased by his share of ETP’s income and by any increases in his share of ETP’s nonrecourse liabilities. That basis will be decreased, but not below zero, by the amount of all distributions from ETP, by the unitholder’s share of ETP’s losses, by any decreases in his share of ETP’s nonrecourse liabilities and by his share of ETP’s expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of ETP’s debt that is recourse to its general partner to the extent of the general partner’s “net value” as defined in regulations under Section 752 of the Code, but will have a share, generally of ETP’s nonrecourse liabilities based on his share of the unrealized appreciation (or depreciation) in ETP’s assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of ETP’s profits. Please read “— Disposition of ETP Common Units — Recognition of Gain or Loss” below.

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of ETP’s losses will be limited to his tax basis in his ETP units and, in the case of an individual unitholder, estate, trust, or 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 ETP’s 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 ETP 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 ETP’s 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 ETP, 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 his units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of ETP’s nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the Internal Revenue Code contains certain passive loss limitations, which 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 generally applied separately with respect to each publicly traded partnership. However, the application of the passive loss limitations to tiered partnerships is uncertain. ETP will take the position that any passive losses it generates that are reasonably allocable to its investment in any publicly-traded partnership in which it now or may in the future own an interest will only be available to offset its passive income generated in the future that is reasonably allocable to such publicly-traded partnership, and will not be available to offset income from other passive activities or investments, including other investments in private businesses or investments ETP may make in other publicly traded partnerships. Moreover, because the passive loss limitations are applied separately with respect to each publicly traded partnership, any passive losses ETP generates will not be available to offset your income from other passive activities or investments, including your investments in other publicly traded partnerships or your

 

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salary, active business or other income. Consequently, any passive losses ETP generates will only be available to offset ETP’s passive income generated in the future and will not be available to offset income from ETP’s passive activities or investments, including investments in private businesses or other publicly traded partnerships. Moreover, any passive losses ETP generates will not be available to offset a unitholder’s income from other passive activities or investments, including his investments in other publicly traded partnerships or the unitholder’s salary, active business or other income. Further, a unitholder’s share of ETP’s net income may be offset by any suspended passive losses from his investment in ETP, but may not be offset by the unitholder’s current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income ETP generates may be deducted in full when he disposes of his entire investment in ETP in a fully taxable transaction with an unrelated party.

The IRS could take the position that for purposes of applying the passive loss limitation rules to tiered publicly traded partnerships, the related entities are treated as one publicly traded partnership. In that case, any passive losses ETP generates would be available to offset income from your investments in other publicly traded partnerships in which ETP owns an interest. However, passive losses that are not deductible because they exceed a unitholder’s share of income ETP generates would not be deducible in full until a unitholder disposes of his entire investment in ETP and any other publicly traded partnerships in which ETP owns an interest in a fully taxable transaction with an unrelated party.

The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

Limitations on Interest Deductions

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

 

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interest on indebtedness properly allocable to property held for investment;

 

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ETP’s interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment 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 ETP’s portfolio income will be treated as investment income.

Entity-Level Collections

If ETP is required or elects under applicable law to pay any Federal, state, local or foreign income tax on behalf of any unitholder or its general partner or any former unitholder, ETP is authorized to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf such payment was made. If the payment is made on behalf of a person whose identity cannot be determined, ETP is authorized to treat the payment as a distribution to all current unitholders. ETP is authorized to amend its 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

 

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distributions otherwise applicable under its partnership agreement is maintained as nearly as is practicable. Payments by ETP 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 ETP has a net profit, its items of income, gain, loss and deduction will be allocated among its general partner and the unitholders in accordance with their percentage interests in ETP. At any time that incentive distributions are made to its general partner, gross income will be allocated to the recipients to the extent of these distributions. If ETP has a net loss, that loss will be allocated first to its general partner and the unitholders in accordance with their percentage interests in ETP to the extent of their positive capital accounts and, second, to ETP’s general partner.

Specified items of ETP’s income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of its assets at the time such assets are contributed to ETP and at the time of any subsequent offering of ETP units, referred to in this discussion as a “Book-Tax Disparity.” As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. 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 ETP does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of ETP’s income and gain will be allocated in an amount and manner sufficient to eliminate such negative capital account balances as quickly as possible.

An allocation of items of ETP’s income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the Book-Tax Disparity, will generally be given effect for U.S. 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 ETP, which will be determined by taking into account all the facts and circumstances, including:

 

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his relative contributions to ETP;

 

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the interests of all the partners in profits and losses;

 

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the interest of all the partners in cash flow; and

 

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the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of ETP Common Units — Allocations Between Transferors and Transferees,” allocations under ETP’s partnership agreement will be given effect for U.S. 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 to have 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:

 

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any of ETP’s income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

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while not entirely free from doubt, all such distributions would appear to be taxable for U.S. federal income tax purposes as ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose ETP common units are loaned to a short seller to cover a short sale of ETP common units. 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 and 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 ETP Common Units — Recognition of Gain or Loss” below.

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of ETP’s 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 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 twelve months) of individuals is 15%. These rates are scheduled to sunset after December 31, 2012, and, thereafter, absent new legislation, the U.S. federal income tax rates on both ordinary income and long-term capital gains will increase to 39.6% and 20%, respectively. Further, such rates are subject to change by new legislation at any time.

The 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 ETP’s income and gain realized 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 and (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, and (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

ETP has 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 ETP Common Units — Constructive Termination.” The election will generally permit ETP to adjust a common unit purchaser’s tax basis in its assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases ETP common units directly from ETP. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in ETP’s assets with respect to a unitholder will be considered to have two components: (i) his share of ETP’s tax basis in its assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.

 

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Where the remedial allocation method is adopted (which ETP has historically done), 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 that is subject to depreciation under Section 168 of the Internal Revenue Code and 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 straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under ETP’s partnership agreement, ETP’s 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. Please read “— Disposition of ETP Common Units — Uniformity of Units.”

ETP intends 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) and Treasury Regulation Section 1.197-2(g)(3), which is not expected to directly apply to a material portion of ETP’s assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, ETP will apply the rules described in the Treasury Regulations and legislative history. If ETP determines that this position cannot reasonably be taken, ETP 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 “Disposition of ETP Common Units — Uniformity of Units.”

A unitholder’s tax basis for his common units is reduced by his share of ETP’s deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position ETP takes that understates deductions will overstate the common unitholder’s basis in his ETP common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of ETP Common Units — Recognition of Gain or Loss.” Vinson & Elkins L.L.P. is unable to opine as to whether ETP’s method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if ETP uses an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge ETP’s position with respect to depreciating or amortizing the Section 743(b) adjustment ETP takes to preserve the uniformity of the units. If such challenge was sustained, the gain from the sale of units might be increased without the benefit of additional deductions. Please see “— Disposition of ETP Common Units — Uniformity of Units.”

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 ETP’s 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 ETP’s 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 ETP’s 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 ETP if ETP has a substantial built-in loss immediately after the transfer, or if ETP distributes property and there is a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

 

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of ETP’s assets and other matters. For example, the allocation of the Section 743(b) adjustment among ETP’s 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 ETP to its 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 ETP’s tangible assets. ETP cannot assure unitholders that the determinations ETP makes 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 ETP’s opinion, the expense of compliance exceed the benefit of the election, ETP may seek permission from the IRS to revoke ETP’s Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

ETP uses the year ending December 31 as its taxable year and the accrual method of accounting for U.S. federal income tax purposes. Each unitholder will be required to include in income his share of ETP’s income, gain, loss and deduction for its 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 ETP’s taxable year but before the close of his taxable year must include his share of ETP’s 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 ETP’s income, gain, loss and deduction. Please read “— Disposition of ETP Common Units — Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of ETP’s assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The U.S. federal income tax burden associated with the difference between the fair market value of ETP’s assets and their tax basis immediately prior to any offering will be borne by the partnership’s unitholders prior to any such offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, ETP 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 “— Disposition of ETP Common Units — Uniformity of Units.” Property ETP subsequently acquires or constructs may be depreciated using accelerated methods permitted by the Internal Revenue Code.

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

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

 

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Valuation and Tax Basis of ETP’s Properties

The U.S. federal income tax consequences of the ownership and disposition of units will depend in part on ETP’s estimates of the relative fair market values, and the tax bases, of ETP’s assets. Although ETP may from time to time consult with professional appraisers regarding valuation matters, ETP will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If ETP’s 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 may incur interest and penalties with respect to those adjustments.

Disposition of ETP Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of ETP’s nonrecourse liabilities. Because the amount realized includes a unitholder’s share of ETP’s 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 ETP that in the aggregate were in excess of cumulative net taxable income for an ETP common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the ETP 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. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss to the extent attributable to Section 751 Assets of ETP. Ordinary income attributable to Section 751 Assets 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 ETP 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 ETP common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific ETP common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of ETP common units transferred must consistently use that identification method for all subsequent sales or exchanges of ETP common units. A unitholder considering the acquisition of additional ETP common units or a sale of units acquired in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

 

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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:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract,

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, ETP’s taxable income and losses will be determined annually, will be prorated on a monthly basis and will be 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 ETP refers to in this disclosure as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of ETP’s 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 employ such 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, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been definitively 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, ETP’s taxable income or losses might be reallocated among the unitholders. ETP is authorized to revise its 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 ETP’s 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 ETP 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 ETP in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, ETP is required to notify the IRS of that transaction and to

 

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furnish specified information to the transferor and transferee. Failure to notify ETP of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

ETP 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 ETP’s 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 constructive termination results in the closing of ETP’s 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 ETP’s taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in ETP 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. ETP’s termination currently would not affect ETP’s classification as a partnership for U.S. federal income tax purposes, but instead, ETP would be treated as a new partnership for tax purposes. ETP would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of ETP’s deductions for depreciation. A termination could also result in penalties if ETP was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject ETP to, any tax legislation enacted before the termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

ETP cannot match transferors and transferees of units. ETP endeavors to maintain uniformity of the economic and tax characteristics of the units to a subsequent purchaser of these units. In the absence of uniformity, ETP may be unable to comply completely with a number of U.S. 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.”

ETP intends to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of ETP’s 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, ETP will apply the rules described in the Treasury Regulations and legislative history. If ETP determines that this position cannot reasonably be taken, ETP 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 common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in ETP’s assets. If this

 

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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 ETP determines that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If ETP chooses not to utilize this aggregate method, ETP 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,” Vinson & Elkins L.L.P. 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 “— Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. A tax-exempt entity or a non-U.S. person should consult its tax advisor before acquiring or investing in the ETP common units.

Employee benefit plans and most other organizations exempt from U.S. federal income tax, including individual retirement accounts and other retirement plans, are subject to U.S. federal income tax on their unrelated business taxable income. Virtually all of ETP’s income allocated to a unitholder that is a tax-exempt organization is expected to be unrelated business taxable income and consequently will be taxable to such holders.

        Non-resident aliens and foreign corporations, trusts or estates that own ETP common units will be considered to be engaged in business in the United States because of the ownership of such units. As a consequence, they will be required to file U.S. federal tax returns to report their share of ETP’s income, gain, loss or deduction and pay U.S. federal income tax at regular rates on their share of ETP’s net income or gain. Moreover, under rules applicable to publicly traded partnerships, ETP’s quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to ETP’s 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 ETP to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of ETP’s 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 U.S. 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 an ETP 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 United States 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 an ETP common unit if (i) he owned (directly or constructively

 

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applying certain attribution rules) more than 5% of ETP’s 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 ETP’s assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the ETP common units or the five-year period ending on the date of disposition. Currently, more than 50% of ETP’s assets consist of U.S. real property interests and ETP does not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to U.S. federal income tax on gain from the sale or disposition of their units.

Recent changes in law may affect certain foreign unitholders. Please read “— Administrative Matters — Additional Withholding Requirements.”

Administrative Matters

Information Returns and Audit Procedures

ETP intends 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 ETP’s income, gain, loss and deduction for ETP’s preceding taxable year. In preparing this information, which will not be reviewed by counsel, ETP will take various accounting and reporting positions, some of which have been mentioned above, to determine each unitholder’s share of income, gain, loss and deduction. ETP cannot assure unitholders 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 ETP nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit ETP’s U.S. 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 ETP’s returns as well as those related to ETP’s 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. ETP’s partnership agreement names its general partner as its Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on ETP’s 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 ETP’s returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in ETP 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. The Tax Matters Partner may select the forum for judicial review, and, if the Tax Matters Partner selects the Court of Federal Claims or a District Court, rather than the Tax Court, partners may be required to pay any deficiency asserted by the IRS before judicial review is available.

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

 

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Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States paid to a foreign financial institution or to a non-financial foreign entity, unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) 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 clause (i) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders.

Although these rules currently apply to applicable payments made after December 31, 2012, the IRS has issued proposed Treasury Regulations providing that the withholding provisions described above will generally apply to payments of FDAP Income made on or after January 1, 2014 and to payments of relevant gross proceeds made on or after January 1, 2015.

The proposed Treasury Regulations described above will not be effective until they are issued in their final form, and as of the date of this prospectus, it is not possible to determine whether the proposed regulations will be finalized in their current form or at all. Each prospective unitholder should consult his own tax advisor regarding these withholding provisions.

Nominee Reporting

Persons who hold an interest in ETP as a nominee for another person are required to furnish to ETP:

 

•

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

 

•

whether the beneficial owner is:

 

(1)

a person that is not a U.S. person;

 

(2)

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

 

(3)

a tax-exempt entity;

 

•

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

 

•

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

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to ETP. The nominee is required to supply the beneficial owner of the units with the information furnished to ETP.

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

 

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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 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

•

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

 

•

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

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, ETP must disclose the pertinent facts on its tax return. In addition, ETP 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 ETP does not believe includes ETP, or any of its investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (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 than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. ETP does 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 ETP was to engage in a “reportable transaction,” ETP (and possibly its unitholders 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 six successive tax years. ETP’s participation in a reportable transaction could increase the likelihood that its U.S. federal income tax information return (and possibly unitholder’s tax return) would be audited by the IRS. Please read “— Administrative Matters — Information Returns and Audit Procedures.”

Moreover, if ETP was to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, unitholders may be subject to the following additional consequences:

 

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;

 

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•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

•

in the case of a listed transaction, an extended statute of limitations.

ETP does not expect to engage in any “reportable transactions.”

Recent Legislative Developments

The present U.S. federal income tax treatment of publicly traded partnerships, including ETP, or an investment in ETP’s common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Currently, one such legislative proposal would eliminate the qualifying income exception upon which ETP relies for its treatment as a partnership for U.S. federal income tax purposes. Please read “— Partnership Status.” ETP is unable to predict whether any such legislation will ultimately be enacted. However, it is possible that a change in law could affect ETP and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in ETP common units.

State, Local, Foreign and Other Tax Considerations

In addition to U.S. federal income taxes, a unitholder may 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 ETP does business or owns property or in which the unitholder is a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider the potential impact of such taxes on his investment in ETP. ETP currently owns property or does business in more than 40 states. Most of these states impose an income tax on individuals, corporations and other entities. ETP may also own property or do business in other jurisdictions in the future. Although a unitholder may not be required to file a return and pay taxes in some jurisdictions because the unitholder’s income from that jurisdiction falls below the filing and payment requirement, the unitholder will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which ETP does business or owns 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 ETP, or ETP 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 may be treated as if distributed to unitholders for purposes of determining the amounts distributed by ETP. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections” above. Based on current law and ETP’s estimate of ETP’s future operations, ETP’s 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 states, localities and foreign jurisdictions, of his investment in ETP. Accordingly, each prospective unitholder is urged to consult 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 U.S. federal tax returns that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in ETP.

 

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INVESTMENTS IN US BY EMPLOYEE BENEFIT PLANS

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.

General Fiduciary Matters

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 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.

Prohibited Transaction Issues

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 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 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 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

 

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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 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.

Representation

Accordingly, by acceptance of the debt securities, each purchaser and subsequent transferee of the 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 notes constitutes assets of any employee benefit plan or (ii) the purchase and holding (and any conversion, if applicable) of the notes 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.

Plan Asset Issues

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 issued with a feature that allows their conversion to equity securities, the securities into which they will be convertible will satisfy 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.

 

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PLAN OF DISTRIBUTION

We may sell or distribute the securities included in this prospectus through underwriters, agents or broker-dealers, in private transactions, at market prices prevailing at the time of sale, at prices related to the prevailing market prices, or at negotiated prices.

In addition, we may sell some or all of the securities included in this prospectus through:

 

•

a block trade in which a broker-dealer may resell a portion of the block, as principal, in order to facilitate the transaction;

 

•

purchases by a broker-dealer, as principal, and resale by the broker-dealer for its account; or

 

•

ordinary brokerage transactions and transactions in which a broker solicits purchasers.

In addition, we may enter into option or other types of transactions that require us to deliver common units to a broker-dealer, who will then resell or transfer the common units under this prospectus. We may enter into hedging transactions with respect to our securities. For example, we may:

 

•

enter into transactions involving short sales of the common units by broker-dealers;

 

•

sell common units short themselves and deliver the units to close out short positions;

 

•

enter into option or other types of transactions that require us to deliver common units to a broker-dealer, who will then resell or transfer the common units under this prospectus; or

 

•

loan or pledge the common units to a broker-dealer, who may sell the loaned units or, in the event of default, sell the pledged units.

We may enter into derivative transactions with third parties, or sell securities not covered by this prospectus to third parties in privately negotiated transactions. If the applicable prospectus supplement indicates, in connection with those derivatives, the third parties may sell securities covered by this prospectus and the applicable prospectus supplement, including in short sale transactions. If so, the third party may use securities pledged by us or borrowed from us or others to settle those sales or to close out any related open borrowings of securities, and may use securities received from us in settlement of those derivatives to close out any related open borrowings of securities. The third party in such sale transactions will be an underwriter and, if not identified in this prospectus, will be identified in the applicable prospectus supplement (or a post-effective amendment). In addition, we may otherwise loan or pledge securities to a financial institution or other third party that in turn may sell the securities short using this prospectus. Such financial institution or other third party may transfer its economic short position to investors in our securities or in connection with a concurrent offering of other securities.

There is currently no market for any of the securities, other than our common units listed on the New York Stock Exchange. If the securities are traded after their initial issuance, they may trade at a discount from their initial offering price, depending on prevailing interest rates, the market for similar securities and other factors. While it is possible that an underwriter could inform us that it intends to make a market in the securities, such underwriter would not be obligated to do so, and any such market making could be discontinued at any time without notice. Therefore, we cannot assure you as to whether an active trading market will develop for these other securities. We have no current plans for listing the debt securities on any securities exchange; any such listing with respect to any particular debt securities will be described in the applicable prospectus supplement.

Any broker-dealers or other persons acting on our behalf that participate with us in the distribution of the common units may be deemed to be underwriters and any commissions received or profit realized by them on the resale of the common units may be deemed to be underwriting discounts and commissions under the Securities Act of 1933, as amended, or the Securities Act. As of the date of this prospectus, we are not a party to any agreement, arrangement or understanding between any broker or dealer and us with respect to the offer or sale of the securities pursuant to this prospectus.

 

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We may have agreements with agents, underwriters, dealers and remarketing firms to indemnify them against certain civil liabilities, including liabilities under the Securities Act. Agents, underwriters, dealers and remarketing firms, and their affiliates, may engage in transactions with, or perform services for, us in the ordinary course of business. This includes commercial banking and investment banking transactions.

At the time that any particular offering of securities is made, to the extent required by the Securities Act, a prospectus supplement will be distributed setting forth the terms of the offering, including the aggregate number of securities being offered, the purchase price of the securities, the initial offering price of the securities, the names of any underwriters, dealers or agents, any discounts, commissions and other items constituting compensation from us and any discounts, commissions or concessions allowed or reallowed or paid to dealers.

Underwriters or agents could make sales in privately negotiated transactions and/or any other method permitted by law, including sales deemed to be an “at the market” offering as defined in Rule 415 promulgated under the Securities Act, which includes sales made directly on or through the New York Stock Exchange, the existing trading market for our common units, or sales made to or through a market maker other than on an exchange.

Securities may also be sold directly by us. In this case, no underwriters or agents would be involved.

If a prospectus supplement so indicates, underwriters, brokers or dealers, in compliance with applicable law, may engage in transactions that stabilize or maintain the market price of the securities at levels above those that might otherwise prevail in the open market.

Pursuant to a requirement by the Financial Industry Regulatory Authority, or FINRA, the maximum commission or discount to be received by any FINRA member or independent broker/dealer may not be greater than eight percent (8%) of the gross proceeds received by us for the sale of any securities being registered pursuant to SEC Rule 415 under the Securities Act of 1933.

If more than 10% of the net proceeds of any offering of securities made under this prospectus will be received by FINRA members participating in the offering or affiliates or associated persons of such FINRA members, the offering will be conducted in accordance with the National Association of Securities Dealers Conduct Rule 5110.

 

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LEGAL MATTERS

The validity of the securities offered in this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Vinson & Elkins L.L.P. 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.

EXPERTS

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 registration statement, 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 registration statement 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 registration statement 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 at 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 by reference in Energy Transfer Partners, L.P.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on June 25, 2012, and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

 

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WHERE YOU CAN FIND MORE INFORMATION

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.

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

 

•

our annual report on Form 10-K for the year ended December 31, 2011;

 

•

our quarterly reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012;

 

•

our current reports on Form 8-K or Form 8-K/A filed on January 4, 2012, January 9, 2012, January 13, 2012 (two reports), January 17, 2012, March 28, 2012, April 30, 2012, May 1, 2012, June 6, 2012, June 18, 2012, June 20, 2012, June 25, 2012, July 3, 2012, August 17, 2012 and September 19, 2012 (excluding any information furnished pursuant to Item 2.02 or Item 7.01 of any such current report on Form 8-K or Form 8-K/A);

 

•

the description of our common units in our registration statement on Form 8-A (File No. 1-11727) filed pursuant to the Securities Exchange Act of 1934 on May 16, 1996; and

 

•

all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 after the date on which the registration statement that includes this prospectus was initially filed with the SEC (excluding any information furnished pursuant to Item 2.02 or Item 7.01 of any current report on Form 8-K or Form 8-K/A).

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:

Energy Transfer Partners, L.P.

3738 Oak Lawn Avenue

Dallas, TX 75219

Attention: Thomas P. Mason

Telephone: (214) 981-0700

 

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PROSPECTUS SUPPLEMENT

 

 

 

 

 

 

 

 

May 9, 2013