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File Pursuant to Rule 424(b)(3)
Registration No. 333-192327

 

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

 

SUBJECT TO COMPLETION, DATED NOVEMBER 14, 2013

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus dated November 14, 2013)

$400,000,000

 

Energy Transfer Equity, L.P.

% Senior Notes due 2024

 

 

We are offering $400,000,000 aggregate principal amount of our         % Senior Notes due 2024 (the “notes”). Interest on the notes will accrue from             , 2013 and will be payable semi-annually on                     and                     of each year, beginning on                     , 2014. The notes will mature on                     , 2024.

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

We also have the option at any time on or after                     , 2023 (which is the date that is three months prior to the maturity date of the notes) to redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date.

The notes initially will be secured on a first-priority basis with the loans under our senior secured revolving credit facility, our senior secured term loan facility and the obligations under our existing 7.500% Senior Notes due 2020 (the “2020 Notes”), by a lien on substantially all of our and certain of our subsidiaries’ tangible and intangible assets that from time to time secure our obligations under such indebtedness, subject to certain exceptions and permitted liens and subject to the terms of a collateral agency agreement. A portion of the collateral will not be pledged until no later than December 31, 2013. The liens securing the notes will be released in full if liens do not secure more than a threshold level of senior obligations (so long as liens securing the 2020 Notes are similarly released), after which the notes will be unsecured. The notes will be our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated indebtedness and senior to any of our future subordinated indebtedness.

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

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

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

Investing in the notes involves risks. See “Risk Factors” beginning on page S-22 of this prospectus supplement and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the notes.

 

		Per Note		Total
Price to Public(1)		%		$
Underwriting Discount		%		$
Proceeds to Energy Transfer Equity, L.P. (Before Expenses)		%		$

 

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

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

Joint Global Coordinators and Joint Book-Running Managers

 

Credit Suisse		Deutsche Bank Securities
Citigroup		Goldman, Sachs & Co.

Joint Book-Running Managers

 

Barclays Capital		BofA Merrill Lynch		Mitsubishi UFJ Securities		Mizuho Securities
Morgan Stanley		RBC Capital Markets		RBS		UBS Investment Bank

The date of this prospectus supplement is                 , 2013.

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TABLE OF CONTENTS

Prospectus Supplement

 

		Page
PROSPECTUS SUPPLEMENT SUMMARY			S-5
RISK FACTORS			S-22
USE OF PROCEEDS			S-59
CAPITALIZATION			S-60
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA			S-62
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			S-63
DESCRIPTION OF OTHER INDEBTEDNESS			S-96
DESCRIPTION OF NOTES			S-108
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS			S-139
UNDERWRITING			S-143
LEGAL MATTERS			S-146
EXPERTS			S-146
INDEX TO FINANCIAL STATEMENTS			F-1

 

Prospectus

 

		Page
ABOUT THIS PROSPECTUS			1
ENERGY TRANSFER EQUITY, L.P.			1
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS			3
RISK FACTORS			5
USE OF PROCEEDS			5
RATIO OF EARNINGS TO FIXED CHARGES			5
DESCRIPTION OF DEBT SECURITIES			6
PLAN OF DISTRIBUTION			9
LEGAL MATTERS			10
EXPERTS			10
WHERE YOU CAN FIND MORE INFORMATION			11
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE			11

 

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ABOUT THIS PROSPECTUS SUPPLEMENT

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

 

•

this prospectus supplement, which provides a summary of the specific terms of the notes; and

 

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the accompanying prospectus, which provides general information, some of which may not apply to the notes.

You should rely only on the information contained in this prospectus supplement, the accompanying prospectus, any free writing prospectus prepared by us or on our behalf and the documents we have incorporated by reference herein. We and the underwriters have not authorized anyone else to give you different information. We and the underwriters are not offering the notes in any jurisdiction where offers and sales are not permitted. You should not assume that the information in this prospectus supplement or in the accompanying prospectus is accurate as of any date other than the date of such information and in no case as of any date subsequent to the date on the front cover of this prospectus supplement. If the description of this offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement. You should not assume that any information contained in the documents incorporated by reference in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates.

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

WHERE YOU CAN FIND MORE INFORMATION

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

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

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

We are incorporating by reference in this prospectus supplement and the accompanying prospectus information we file with the SEC, which means that we are disclosing important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus supplement and the accompanying prospectus, and later information that we file with the SEC automatically will update and supersede this information and will be considered a part of this prospectus supplement from the date those documents are filed. We incorporate by reference the documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended,

 

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excluding any information in those documents that is deemed by the rules of the SEC to be furnished not filed, until we close this offering:

 

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our Annual Report on Form 10-K for the year ended December 31, 2012;

 

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our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013;

 

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our Current Reports on Form 8-K filed February 14, 2013, February 28, 2013, March 26, 2013, April 2, 2013, April 4, 2013, May 1, 2013 (which was amended by Form 8-K/A on May 6, 2013), June 24, 2013, August 8, 2013, October 25, 2013, November 1, 2013 and November 14, 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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Item 1A Risk Factors of ETP’s Annual Report on Form 10-K for the year ended December 31, 2012; and

 

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Item 1A Risk Factors of Regency’s Annual Report on Form 10-K for the year ended December 31, 2012.

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 web site 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 web site at the address provided above or by writing or calling us at the address set forth below.

Energy Transfer Equity, L.P.

3738 Oak Lawn Avenue

Dallas, Texas 75219

Attention: Sonia Aubé

Telephone: (214) 981-0700

 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This prospectus supplement, the accompanying prospectus and the documents we incorporate by reference herein and therein contain various forward-looking statements and information that are based on our beliefs and those of our general partner, LE GP, LLC, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this prospectus supplement, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” 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 ability of our subsidiaries, ETP and Regency, to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

 

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the actual amount of cash distributions by ETP and Regency to us;

 

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the volumes transported on our subsidiaries’ pipelines and gathering systems;

 

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the level of throughput in our subsidiaries’ processing and treating facilities;

 

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the fees our subsidiaries charge and the margins they realize for their 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 (“NGLs”);

 

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energy prices generally;

 

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

 

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the general level of petroleum product demand and the availability and price of NGL supplies;

 

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the level of domestic oil, natural gas and NGL production;

 

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the availability of imported oil, natural gas and NGLs;

 

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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, natural gas and NGLs;

 

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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 subsidiaries’ 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;

 

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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 subsidiaries’ pipelines and facilities;

 

•

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

 

•

the nonpayment or nonperformance by our subsidiaries’ customers;

 

•

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

 

•

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

 

•

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

 

•

a deterioration of the credit and capital markets;

 

•

risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interest, including risks related to management actions at such entities that our subsidiaries may not be able to control or influence;

 

•

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;

 

•

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

 

•

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 supplement. Any forward-looking statement made by us in this prospectus supplement and the documents incorporated by reference into this prospectus supplement is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

 

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RISK FACTORS

An investment in the notes involves risks. You should consider carefully the following risk factors and the risk factors set forth beginning on page 5 of the accompanying prospectus and in our, ETP’s and Regency’s Annual Reports on Form 10-K for the year ended December 31, 2012, in each case as updated by our, ETP’s and Regency’s subsequent Quarterly Reports on Form 10-Q, together with all of the other information included in, or incorporated by reference into, this prospectus supplement and the accompanying prospectus, when evaluating an investment in the notes. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations. The risks discussed below also include forward-looking statements and our actual results may differ substantially from those discussed in these forward-looking statements. See “Forward-Looking Statements.”

Risks Related to Our Indebtedness and the Notes

The notes will be effectively subordinated to liabilities and indebtedness of our subsidiaries.

We do not own any operating assets. Our principal assets consist of approximately 49.6 million common units of ETP, approximately 50.2 million Class H units of ETP and 26.3 million common units of Regency, in addition to the incentive distribution rights and general partner interests of ETP and Regency. We own these incentive distribution rights and general partner interests through wholly owned subsidiaries. Initially, none of our subsidiaries will guarantee our obligations with respect to the notes. Creditors of our subsidiaries that do not guarantee the notes will have claims with respect to the assets of those subsidiaries that rank effectively senior to claims of the holders of the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of those creditors must be satisfied prior to making any such distribution or payment to us in respect of our direct or indirect equity interests in such subsidiaries. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of the notes. Also, there are federal and state laws that could invalidate any guarantee of our subsidiary or subsidiaries that guarantee the notes. If that were to occur, the claims of creditors of a guaranteeing subsidiary would also rank effectively senior to the notes, to the extent of the assets of that subsidiary. Furthermore, such subsidiaries are not prohibited under the indenture from incurring additional indebtedness.

None of ETP, Regency or any of their respective subsidiaries will initially guarantee the payment of the notes, and our ability to pay principal and interest on the notes is dependent upon ETP and Regency having sufficient cash available for distributions on their respective common units, Class H units (in the case of ETP) and incentive distribution rights after satisfaction of the debt obligations of ETP, Regency and their respective subsidiaries.

None of ETP, Regency or any of their respective subsidiaries will initially guarantee our obligations with respect to the notes. Therefore, none of ETP, Regency or any of their respective subsidiaries will have any obligations to pay amounts due under the notes or to make any funds available to pay those amounts. Our ability to pay principal and interest on the notes is dependent upon our receipt of cash distributions from ETP and Regency in respect of our ETP and Regency common units, Class H units (in the case of ETP) and incentive distribution rights, which cash distributions are subject to the priority rights of creditors of ETP, Regency and their respective subsidiaries. Accordingly, creditors of ETP, Regency and their respective subsidiaries will have claims, with respect to the assets of ETP, Regency and their respective subsidiaries, that rank effectively senior to the notes. In the event of any distribution or payment of assets of ETP, Regency and their respective subsidiaries in any dissolution, winding up, liquidation, reorganization or other bankruptcy proceeding, the claims of the creditors of ETP, Regency and their respective subsidiaries must be satisfied prior to ETP or Regency making any such distribution to us in respect of our direct or indirect equity interests in ETP or Regency. Accordingly, after satisfaction of the claims of such creditors, there may be little or no amounts distributed to us to make payments in respect of the notes. As of September 30, 2013, the notes would have been effectively subordinated

 

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to approximately $19.3 billion of principal amount of outstanding indebtedness of ETP, Regency and their respective subsidiaries, as well as other significant liabilities. Furthermore, none of ETP, Regency or any of their respective subsidiaries is subject to any provisions of the indenture, and therefore the indenture does not prohibit ETP, Regency or any of their respective subsidiaries from incurring additional indebtedness.

We will have a substantial amount of indebtedness following this offering, which may adversely affect our ability to operate our business, remain in compliance with debt covenants and make payments on our indebtedness, including the notes.

We have significant debt obligations. If we are unable to meet our debt obligations, we may need to consider refinancing or amending credit agreements or debt indentures or adopting alternative strategies to reduce or delay expenditures or seeking additional equity capital. As of September 30, 2013, after giving effect to (i) the Tender Offer, (ii) the entry into our new revolving credit facility and term loan facility and (iii) this offering and the application of the net proceeds therefrom, we would have had approximately $2.8 billion of indebtedness outstanding. In addition, our subsidiaries, including ETP, Regency and their respective subsidiaries, had outstanding approximately $19.3 billion of indebtedness as of September 30, 2013 that would effectively rank senior to the notes with respect to the assets of those subsidiaries, as well as other significant liabilities.

Our substantial debt could have important consequences to you. For example, it could make it more difficult for us to satisfy our obligations with respect to the notes, increase our vulnerability to general adverse economic and industry conditions, and limit our ability to borrow additional funds, even when necessary to maintain adequate liquidity. In addition, the indenture governing the notes and the 2020 Notes, the agreements governing our revolving and term loan facilities and any of our future debt agreements may contain financial and other restrictive covenants that will limit our ability to decide how to operate our business. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our outstanding indebtedness.

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

As of September 30, 2013, after giving effect to (i) the Tender Offer, (ii) the entry into our new revolving credit facility and new term loan facility and (iii) this offering and the application of the net proceeds therefrom, we would have had approximately $2.8 billion of indebtedness outstanding. In addition, as of September 30, 2013, our subsidiaries, including ETP, Regency and their respective subsidiaries, had approximately $19.3 billion of principal amount of indebtedness, as well as other significant liabilities. We and our subsidiaries, including ETP and Regency, may incur substantial additional indebtedness in the future, including pursuant to our new revolving credit facility. The terms of the indenture do not prohibit us from doing so. If we incur any additional indebtedness, including trade payables, that ranks equally with the notes, the holders of that debt will be entitled to share ratably with you in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of our partnership to unsecured creditors to the extent our collateral is either released or inadequate to satisfy the claims of the holders of the notes. This may have the effect of reducing the amount of proceeds paid to you. If new debt is added to our current debt levels, the related risks that we now face could intensify. See “Description of Notes” and “Description of Other Indebtedness.”

In the event of a default, we may have insufficient funds to make any payments due on the notes.

A breach of any covenant in the indenture governing the notes and the 2020 Notes, the credit agreements governing our new revolving credit facility and new term loan facility and any other debt that we may have outstanding from time to time could result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and a default with respect to, and an acceleration of, the debt outstanding under other debt agreements. The accelerated debt would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt. Even if new financing were available at that time, it may not be

 

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on terms that are acceptable to us. If our debt is in default for any reason, our business, financial condition and results of operations could be materially adversely affected. See “Description of Other Indebtedness.”

Your right to take enforcement action with respect to the liens securing the notes is limited, and you will receive the proceeds from such enforcement pro rata with the holders of the 2020 Notes and the lenders under our new revolving credit facility and new term loan facility.

The notes, the 2020 Notes and the indebtedness and other obligations under our new revolving credit facility and new term loan facility will be secured by liens on the same collateral. However, under the terms of the collateral agency agreement, the holders of the notes will not have any independent power to enforce any liens or to exercise any rights or powers arising under the security documents except through the administrative agents for the lenders under our new revolving credit facility and new term loan facility and the collateral agent. The proceeds of any collection, sale, disposition or other realization of the collateral received in connection with the exercise of remedies (including distributions of any part of the collateral in a bankruptcy, insolvency, reorganization or similar proceedings) will be shared pro rata with the holders of the 2020 Notes and the lenders under our new revolving credit facility and new term loan facility. By investing in the notes, you will have deemed to have agreed to these restrictions. As a result of these restrictions, holders of the notes will have limited remedies and recourse against us in the event of a default.

There may not be sufficient collateral to pay all or any of the notes.

Our indebtedness and other obligations under our new revolving credit facility and new term loan facility, the 2020 Notes and the notes are, and certain other secured indebtedness that we may incur in the future will be, secured by a first-priority lien on substantially all of our and certain of our subsidiaries’ assets, subject to certain exceptions and permitted liens and subject to the terms of the collateral agency agreement. No fair market value appraisals of any collateral have been prepared in connection with this offering of the notes. The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. By its nature, some or all of the collateral may be illiquid and may have no readily ascertainable market value. Although a public trading market exists for the portion of the collateral represented by the common units of ETP and Regency, the market may not be sufficiently liquid for you to realize that value. The value of the assets pledged as collateral for the notes could be impaired in the future as a result of changing economic conditions, competition or other future trends.

In addition, the collateral securing the notes is subject to liens permitted under the terms of the indenture and the collateral agency agreement, whether arising on or after the date the notes were issued. To the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing the notes. The collateral securing the notes may be released in certain circumstances without a release of collateral securing other obligations if such obligations do not exceed a threshold level or qualify as permitted liens. In such an event, the holders of the notes would recover less in a bankruptcy, foreclosure, liquidation or similar proceeding than the holders of such other obligations to the extent of the value of the collateral securing such obligations. The indenture governing the notes offered hereby does not require that we maintain the current level of collateral or maintain a specific ratio of indebtedness to asset values.

In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, no assurance can be given that the proceeds from any sale or liquidation of the collateral will be sufficient to pay our senior secured debt obligations, including the notes, in full or at all. Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the notes. Any claim for the difference between the amount, if any, realized by holders of the notes from the sale of the collateral securing the notes and the obligations under the notes will rank equally in right of payment with all of our unsecured senior indebtedness and other obligations, including trade payables.

 

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The collateral securing the notes may be diluted under certain circumstances.

The new revolving credit facility and new term loan facility and the indenture governing the 2020 Notes and the notes offered hereby will permit us to incur additional debt up to applicable maximum debt threshold amounts. Any additional debt secured by the collateral would dilute the value of the rights the holders of the notes have in the collateral.

Under certain circumstances, the collateral securing the notes may be released, and the notes will thereafter become unsecured.

There are circumstances other than repayment or discharge of the notes under which the collateral securing the notes will be released automatically, without your consent, including:

 

•

if outstanding indebtedness is discharged or if liens on collateral securing obligations are released, then a release of the liens serving the notes will occur in accordance with the covenant described under “Description of Notes—Security for the Notes,” even though we continue to have obligations in an aggregate principal amount under our new revolving credit facility and new term loan credit facility, together with all Attributable Indebtedness from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by clauses (1) through (3), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described in “Description of Notes”) not to exceed the greater of (x) $250.0 million and (y) 10% Net Tangible Assets (each term as defined in “Description of Notes’), or if such liens qualify as “Permitted Liens”; or

 

•

upon the consent of holders of at least two-thirds in principal amount of the notes then outstanding, in accordance with the covenant described under “Description of Notes—Amendments and Waivers.”

If the collateral securing the notes is released, the notes will rank effectively junior to any of our secured indebtedness to the extent of the collateral value of that secured indebtedness.

The collateral agency agreement limits the rights of holders of the notes with respect to the collateral, even during an event of default.

Under the terms of the collateral agency agreement, any actions that may be taken in respect of the collateral, including the ability to cause the commencement of enforcement proceedings against the collateral and the release of the collateral from any lien, will be at the direction of the administrative agents under our new revolving credit facility and our new term loan facility. Neither the trustee nor the collateral agent, on behalf of the holders of notes, will have the ability to control or to direct such actions, even if an event of default under the notes has occurred. See “Description of Notes—Collateral Agency Agreement.” In addition, subject to limitations adversely affecting the equal and ratable treatment of the security interest of the trustee or imposing new material obligations on the trustee, the collateral agent is entitled, without the consent of holders of the notes or the trustee, to amend the terms of the security documents securing the notes and to release the liens of the secured parties on any part of the collateral in accordance with the terms of such agreement. The collateral so released will no longer secure obligations under the notes. See “Description of Notes—Collateral Agency Agreement” and “—Security for the Notes.”

Your interest in the collateral may be adversely affected by the failure to record or perfect security interests in certain collateral.

Applicable law requires that security interests in certain property and rights acquired after the grant of a general security interest can only be perfected at the time such property and rights are acquired and identified. The liens on the collateral securing the notes may not be perfected if the collateral agent is not able to take the

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creditor could gain priority over one or more liens on the collateral securing the notes by recording an intervening lien or liens. Although the indenture contains customary further assurances covenants, there can be no assurance that the trustee or the collateral agent will monitor, or that we will inform the trustee or the collateral agent of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. The collateral agent has no obligation to monitor the acquisition of additional property or rights that constitute collateral or the perfection of any security interest in favor of the holders of the notes against third parties.

Our credit ratings may not reflect all the risks of your investments in the notes.

Our credit ratings are an assessment by rating agencies of our ability to pay our debts when due. Consequently, real or anticipated changes in our credit ratings will generally affect the market value of the notes. These credit ratings may not reflect the potential impact of risks relating to structure or marketing of the notes. Agency ratings are not a recommendation to buy, sell or hold any security, and may be revised or withdrawn at any time by the issuing organization. Each agency’s rating should be evaluated independently of any other agency’s rating.

Bankruptcy laws may limit your ability to realize value from a sale of the collateral securing the notes.

The right of the collateral agent to foreclose upon and sell the collateral securing the notes upon the occurrence of an event of default under the indenture could be restricted under the United States Bankruptcy Code, (the “Bankruptcy Code”), if a bankruptcy case is commenced by or against us before the collateral agent has repossessed and disposed of the collateral. Upon the commencement of a case for relief under Chapter 11 of the Bankruptcy Code, a secured creditor, such as the collateral agent, is prohibited from repossessing its security from a debtor in a bankruptcy case or from disposing of security repossessed from the debtor without bankruptcy court approval. Furthermore, the Bankruptcy Code permits a debtor to continue to retain and to use the collateral (and the proceeds, products, rents or profits of such collateral) even though the debtor is in default under the applicable debt instruments, so long as the secured creditor is afforded “adequate protection” of its interest in the collateral. The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the bankruptcy court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the bankruptcy case. A bankruptcy court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the amount of debt it secures.

In light of the lack of a precise definition of the term “adequate protection” and the broad discretionary powers of bankruptcy courts, it is impossible to predict:

 

•

how long payments under the notes could be delayed following commencement of a bankruptcy case;

 

•

whether or when the collateral agent could repossess or dispose of the collateral;

 

•

the value of the collateral at the time of the bankruptcy petition; or

 

•

whether or to what extent holders of the notes would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

Any disposition of the collateral during a bankruptcy case would also require permission from the bankruptcy court. Furthermore, in the event a bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due under the notes, the holders of the notes would hold secured claims to the extent of the value of the collateral to which the holders of the notes are entitled and unsecured claims with respect to such shortfall. The Bankruptcy Code only permits the payment and accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s bankruptcy case to the extent the value of its collateral is determined by the bankruptcy court to exceed the aggregate outstanding principal amount of the

 

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obligations secured by the collateral. Any proceeds from the collection, sale, disposition or other realization of the collateral that is distributed as part of a bankruptcy will be shared pro rata with the holders of the 2020 Notes and the lenders under our new revolving credit facility and new term loan facility.

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

Upon the occurrence of a change of control triggering event, we will be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control triggering event because we may not have sufficient funds. Further, we may be contractually restricted under the terms of our senior credit facilities, 2020 Notes or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase your notes unless we are able to refinance or obtain waivers under the agreements governing such indebtedness. Our failure to repurchase the notes upon a change of control would cause a default under the indenture governing the notes and a cross-default under our senior credit facilities and 2020 Notes. Our senior credit facilities provide that a change of control, as defined in such agreement, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and, if such debt is not paid, to enforce security interests in the collateral securing such debt, thereby limiting our ability to raise cash to purchase the notes, and reducing the practical benefit of the offer to purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions.

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

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

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

Risks Inherent in an Investment in Us

Our only significant assets are our partnership interests, including the incentive distribution rights, in ETP and Regency and, therefore, our cash flow is dependent upon the ability of ETP and Regency to make distributions in respect of those partnership interests.

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

 

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The amount of cash that ETP and Regency can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 

•

the amount of natural gas transported through ETP’s and Regency’s transportation pipelines and gathering systems;

 

•

the level of throughput in processing and treating operations;

 

•

the fees charged and the margins realized by ETP and Regency for gathering, treating, processing, storage and transportation services;

 

•

the price of natural gas;

 

•

the relationship between natural gas and NGL prices;

 

•

the weather in their respective operating areas;

 

•

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

 

•

the level of their respective operating costs;

 

•

prevailing economic conditions; and

 

•

the level of their respective derivative activities.

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

 

•

the level of capital expenditures they 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;

 

•

debt service requirements;

 

•

fluctuations in working capital needs;

 

•

their ability to make working capital borrowings under their respective credit facilities to make distributions;

 

•

their ability to access capital markets;

 

•

restrictions on distributions contained in their respective debt agreements; and

 

•

the amount, if any, of cash reserves established by the board of directors of their respective general partners in their discretion for the proper conduct of their respective businesses.

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

Furthermore, you should be aware that the amount of cash that ETP and Regency have available for distribution depends primarily upon cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ETP and Regency may make cash distributions during periods when they record net losses and may not make cash distributions during periods when they record net income. Please read the risk factors in ETP’s and Regency’s Annual Reports on Form 10-K for the year ended December 31, 2012, in each case as updated by

 

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ETP’s and Regency’s subsequent Quarterly Reports on Form 10-Q, for a discussion of further risks affecting ETP’s and Regency’s ability to generate distributable cash flow.

See “Description of Other Indebtedness,” as well as our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the nine months ended September 30, 2012, for a summary of such covenant restrictions.

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

Our indirect ownership of 100% of the incentive distribution rights in ETP, through our ownership of equity interests in ETP GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which ETP GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per common unit per quarter would reduce ETP GP’s percentage of the incremental cash distributions above $0.3175 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our general partner interest in ETP and our ETP common units.

As a result of our ownership of Class H units of ETP, we are entitled to, among other things, distributions from ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the incentive distribution rights and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H units, for any previous quarters. ETP (through Sunoco Partners) is entitled to receive its pro rata share of specified percentages of total cash distributions made by Sunoco Logistics as Sunoco Logistics reaches established target cash distribution levels. ETP currently receives its pro rata share of cash distributions from Sunoco Logistics based on the highest incremental percentage, 50%, to which Sunoco Partners is entitled pursuant to its incentive distribution rights in Sunoco Logistics. A decrease in the amount of distributions by Sunoco Logistics to less than $0.5275 per common unit per quarter would reduce Sunoco Partners’ percentage of the incremental cash distributions above $0.1917 per common unit per quarter from 50% to 37%. Any such decrease would have the effect of disproportionately reducing the amount of all distributions that ETP receives from Sunoco Logistics based on its ownership interest in the incentive distribution rights in Sunoco Logistics compared to cash distributions ETP receives from Sunoco Logistics on its general partner interest in Sunoco Logistics and its Sunoco Logistics common units, and would affect the amount of distributions received by ETE from ETP in respect of ETE’s Class H units.

Through our ownership of equity interests in Regency GP, we receive our pro rata share of incremental cash distributions from Regency at the 23% level pursuant to Regency GP’s incentive distribution rights in Regency. A decrease in the amount of distributions by Regency to less than $0.4375 per common unit per quarter would have reduced Regency GP’s percentage of the incremental cash distributions above $0.4025 per common unit per quarter from 23% to 13%. As a result, any such reduction in quarterly cash distributions from Regency would have the effect of disproportionately reducing the amount of all distributions that we receive from Regency based on our ownership interest in the incentive distribution rights of Regency as compared to cash distributions we receive from Regency on our general partner interest in Regency and our Regency common units.

 

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The consolidated debt level and debt agreements of ETP and Regency and those of their subsidiaries may limit the distributions we receive from ETP and Regency, our future financial and operating flexibility and our ability to make required payments on the notes.

As of September 30, 2013, ETP had approximately $16.3 billion of principal amount of consolidated debt outstanding, excluding the credit facilities of its joint ventures, which it guarantees in part, and Regency had approximately $3.0 billion of principal amount of consolidated debt outstanding. ETP’s and Regency’s levels of indebtedness affect their operations in several ways, including, among other things:

 

•

a significant portion of ETP’s and Regency’s cash flows from operations will be dedicated to the payment of principal and interest on then outstanding debt and will not be available for other purposes, including payment of distributions to us;

 

•

covenants contained in ETP’s and Regency’s existing debt arrangements require ETP and Regency to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;

 

•

ETP’s and Regency’s ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

 

•

ETP and Regency may be at a competitive disadvantage relative to similar companies that have less debt;

 

•

ETP and Regency may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels; and

 

•

failure to comply with the various restrictive covenants of the debt agreements could negatively impact ETP’s and Regency’s ability to incur additional debt, including their ability to utilize the available capacity under their respective revolving credit facilities, and to pay distributions.

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

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

 

•

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 reimburse our general partner for all expenses it has incurred on our behalf;

 

•

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.

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

 

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We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, the 2020 Notes and the indebtedness under our credit facilities, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

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

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements, including the credit agreements relating to the revolving and term loan facilities and the indenture governing the 2020 Notes and the notes. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We expect that our revolving and term loan facilities will restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations then due. See “Description of Other Indebtedness” and “Description of Notes.”

ETP, Sunoco Logistics and Regency are not prohibited from competing with us.

Neither our partnership agreement nor the partnership agreements of ETP, Sunoco Logistics or Regency prohibit ETP, Sunoco Logistics or Regency from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, ETP, Sunoco Logistics or Regency may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

 

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

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. 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. As of September 30, 2013, we had approximately $1.72 billion of variable rate debt outstanding, including outstanding borrowings under Regency’s revolving credit facility of $176 million. We also had the following interest rate swaps outstanding as of September 30, 2013:

 

Notional Amount Outstanding

Entity

Term

Type(1)

September 30, 2013

December 31, 2012

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

$

—

$

500

ETP

July 2013(2)

Forward-starting to pay a fixed rate of 4.03% and receive a floating rate

—

400

ETP

July 2014(2)

Forward-starting to pay a fixed rate of 4.25% and receive a floating rate

400

400

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

600

ETP

June 2021

Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%

200

—

ETP

February 2023

Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%

400

—

Southern Union

November 2016

Pay a fixed rate of 2.97% and receive a floating rate

25

75

Southern Union

November 2021

Pay a fixed rate of 3.75% and receive a floating rate

450

450

 

(1)	Floating rates are based on 3-month LIBOR.

(2)

Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. During the nine months ended September 30, 2013, ETP settled $400 million of forward-starting interest rate swaps that had an effective date of July 2013.

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

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

If we cease to manage and control ETP or Regency in the future, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control ETP or Regency and are deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”), we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with

 

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affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes.

If ETP GP, Sunoco Partners or Regency GP withdraws or is removed as ETP’s, Sunoco Logistics’ or Regency’s general partner, as applicable, then we would lose control over the management and affairs of ETP, Sunoco Partners or Regency, the risk that we would be deemed an investment company under the Investment Company Act would be exacerbated and our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP, Sunoco Logistics or Regency could be cashed out or converted into ETP, Sunoco Logistics or Regency common units, as applicable, at an unattractive valuation.

Under the terms of ETP’s, Sunoco Logistics’ or Regency’s respective partnership agreements, ETP GP, Sunoco Partners or Regency GP, as applicable, will be deemed to have withdrawn as general partner if, among other things, it:

 

•

voluntarily withdraws from the partnership by giving notice to the other partners,

 

•

transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s, Sunoco Logistics’ or Regency’s partnership agreement, as applicable,

 

•

makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or

 

•

dissolves itself under Delaware law without reinstatement within the requisite period.

In addition, ETP GP, Sunoco Partners and Regency GP can be removed as ETP’s, Sunoco Logistics’ or Regency’s general partner if that removal is approved by unitholders holding at least 66 ²/₃% of ETP’s, Sunoco Logistics’ or Regency’s respective outstanding common units (including common units held by ETP GP, Sunoco Partners or Regency GP and their respective affiliates). Currently, ETP GP and its affiliates own approximately 15.0% of ETP’s outstanding common units, Sunoco Partners and its affiliates own approximately 32.3% of Sunoco Logistics’ common units and Regency GP and its affiliates own approximately 12.5% of Regency’s outstanding common units.

If ETP GP, Sunoco Partners or Regency GP withdraws from being ETP’s, Sunoco Logistics’ or Regency’s respective general partner in compliance with ETP’s, Sunoco Logistics’ or Regency’s partnership agreement, as applicable, or is removed from being ETP’s, Sunoco Logistics’ or Regency’s respective general partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor general partner to purchase its general partner interests, incentive distribution rights and limited partner interests in ETP, Sunoco Logistics or Regency, as applicable, for fair market value. If ETP GP, Sunoco Partners or Regency GP withdraws from being ETP’s, Sunoco Logistics’ or Regency’s respective general partner in violation of ETP’s, Sunoco Logistics’ or Regency’s partnership agreement, as applicable, or is removed from being ETP’s, Sunoco Logistics’ or Regency’s general partner in circumstances where a court enters a judgment that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s, Sunoco Logistics’ or Regency’s general partner, and the successor general partner does not exercise its option to purchase the general partner interests, incentive distribution rights and limited partner interests in ETP, Sunoco Logistics or Regency, as applicable, for fair market value, then the general partner interests and incentive distribution rights in ETP, Sunoco Logistics or Regency, as applicable, could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP, Sunoco Logistics or Regency GP would lose control over the management and affairs of ETP, Sunoco Logistics or

 

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Regency, as applicable, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act. In addition, our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP, Sunoco Logistics and Regency, to which a significant portion of the value of our common units is currently attributable, could be cashed out or converted into ETP, Sunoco Logistics or Regency common units, as applicable, at an unattractive valuation.

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

The partnership agreements of each of ETP, Sunoco Logistics and Regency allow ETP, Sunoco Logistics and Regency, respectively, to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP, Sunoco Logistics or Regency will have the following effects:

 

•

unitholders’ current proportionate ownership interest in ETP, Sunoco Logistics or Regency, as applicable, will decrease;

 

•

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

 

•

the ratio of taxable income to distributions may increase;

 

•

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

 

•

the market price of ETP’s, Sunoco Logistics’ or Regency’s common units, as applicable, may decline.

The payment of distributions on any additional units issued by ETP, Sunoco Logistics or Regency may increase the risk that ETP, Sunoco Logistics or Regency, as applicable, may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations, including obligations under the notes.

Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay our obligations under our indebtedness.

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

In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available to make payment under our debt obligations.

Risks Related to the Businesses of ETP and Regency

Since our cash flows consist exclusively of distributions from ETP and Regency, risks to the businesses of ETP and Regency are also risks to us. We have set forth below risks to the businesses of ETP and Regency, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.

 

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

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

ETP and Regency are exposed to the credit risk of their respective customers, and an increase in the nonpayment and nonperformance by their respective customers could reduce their respective ability to make distributions to their Unitholders, including to us.

The risks of nonpayment and nonperformance by ETP’s and Regency’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Regency are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers. The current tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Regency’s customers. Any substantial increase in the nonpayment and nonperformance by ETP’s or Regency’s customers could have a material adverse effect on ETP’s or Regency’s respective results of operations and operating cash flows.

Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and oil that are beyond our control.

The prices for natural gas, NGLs and oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and U.S. economic conditions and other factors, including:

 

•

the level of domestic natural gas, NGL, and oil production;

 

•

the level of natural gas, NGL, and oil imports and exports, including liquefied natural gas;

 

•

actions taken by natural gas and oil producing nations;

 

•

instability or other events affecting natural gas and oil producing nations;

 

•

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

 

•

the price, availability and marketing of competitive fuels;

 

•

the demand for electricity;

 

•

the impact of energy conservation and fuel efficiency efforts; and

 

•

the extent of governmental regulation, taxation, fees and duties.

In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2012, the NYMEX natural gas settlement price for the prompt month contract ranged from a high of $3.70 per MMBtu to a low of $2.04 per MMBtu. A composite of the Mont Belvieu average NGLs price based upon our average NGLs composition during our year ended December 31, 2012 ranged from a high of approximately $1.23 per gallon to a low of approximately $0.75 per gallon. Oil spot prices at Cushing, Oklahoma during the year ended December 31, 2012 ranged from a high of approximately $109.39 per barrel to a low of approximately $77.72 per barrel.

Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL and oil commodities could materially affect our profitability.

 

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

We experience competition in all of our business segments. With respect to our intrastate natural gas transportation and storage segment, 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.

Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers 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 and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.

Our crude oil and refined products pipeline operations 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. Further, our 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.

We also face strong competition in the market for the sale of retail gasoline and merchandise. Our 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. The actions of our retail marketing competitors, including the impact of foreign imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations.

We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in oil, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.

The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of, and demand for oil, natural gas and NGLs in the markets we serve and competition from other service providers.

A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers 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 natural gas sales markets primarily on the basis of price.

 

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We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services; while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or the effects of competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive 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. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, 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.

The volume of crude oil and refined products transported through our oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our oil pipelines and terminal facilities could decline.

The loss of existing customers by our midstream, transportation, terminalling and the storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.

Our midstream facilities and transportation pipelines are attached to basins with naturally declining production, which we may not be able to replace with new sources of supply.

In order to maintain or increase throughput levels on our gathering systems 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.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. 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. In addition, we have no control over producers or their production and contracting decisions.

 

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While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. If the reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities decline and are not replaced by other sources of supply, a decrease in development or production activity could cause a decrease in the volume of unreserved services we provide and decrease in the number and volume of our contracts for reserved transportation service over the long run, and in each case, adversely affect our revenues and results of operations.

If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

As a result of our exit from the refining business, we are entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for our retail marketing business.

As a result of our exit from the refining business, we are required to purchase refined products from third party sources, including the joint venture that acquired our Philadelphia refinery. We may also need to contract for new ships, barges, pipelines or terminals which we have not historically used to transport these products to our markets. The inability to acquire refined products and any required transportation services at prices no less favorable than the formerly applicable market-based transfer prices may adversely affect our business and results of operations.

The profitability of certain activities in our natural gas gathering, processing, 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.

For a portion of the natural gas gathered at our systems, 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.

We also 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 revenues and 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.

When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. 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.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas

 

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prices. Increases in natural gas prices tend to increase our fuel retention fees and the value of gas we retain, and decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana 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 use of derivative financial instruments could result in material financial losses by ETP and Regency.

From time to time, ETP and Regency have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Regency hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, even though monitored by management, ETP’s and Regency’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Regency’s physical or financial positions, or internal hedging policies and procedures are not followed.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

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 natural gas and NGL revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.

Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in 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 pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by 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

Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude oil and refined products. Any interruptions or reduction in the

 

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capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our 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 our results of operations, financial position, or cash flows.

The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect our ability to operate and adversely affect our financial results.

Our ability to operate our pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. 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. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, we 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 our business if we were to lose the right to use or occupy the property on which our pipelines are located.

ETP and Regency may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.

ETP and Regency each have strategies that contemplate growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Regency regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Regency believe will present opportunities to realize synergies and increase cash flow.

Consistent with their strategies, managements of ETP and Regency may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP or Regency management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP or Regency believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure that ETP’s or Regency’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.

In addition, ETP and Regency each are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Regency losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s or Regency’s

 

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ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s or Regency’s results of operations.

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

As of December 31, 2012, our consolidated balance sheets reflected $6.43 billion of goodwill and $2.29 billion 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 ETP and Regency do not make acquisitions on economically acceptable terms, their future growth could be limited.

ETP’s and Regency’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.

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

 

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inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

 

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inability to raise financing for such acquisitions on economically acceptable terms; or

 

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inability to outbid by competitors, some of which are substantially larger than ETP or Regency and may have greater financial resources and lower costs of capital.

Furthermore, even if ETP or Regency consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Regency 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 its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;

 

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significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;

 

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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 there is no indemnity or the indemnity is inadequate;

 

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

 

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less effectively manage its 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.

 

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

If ETP and Regency do not continue to construct new pipelines, their future growth could be limited.

During the past several years, ETP and Regency have constructed several new pipelines, and ETP and Regency are currently involved in constructing additional pipelines. ETP’s and Regency’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP or Regency 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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inability to identify pipeline construction opportunities with favorable projected financial returns;

 

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inability to raise financing for its identified pipeline construction opportunities; or

 

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inability to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if ETP or Regency constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.

Expanding ETP’s and Regency’s business by constructing new pipelines and related facilities subjects ETP and Regency to risks.

One of the ways that ETP and Regency have grown their respective businesses is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s and Regency’s control and require the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP or Regency undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s or Regency’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s or Regency’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP or Regency builds a new pipeline, the construction will occur over an extended period of time, but ETP or Regency, as applicable, may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s and Regency’s abilities to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP and Regency may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s or Regency’s expected investment return, which could adversely affect its results of operations and financial condition.

 

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ETP and Regency depend on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s or Regency’s respective business and operating results.

ETP and Regency rely on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP and Regency will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP and Regency may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s and Regency’s business, results of operations, and financial condition.

ETP and Regency depend on key customers to transport natural gas through their pipelines.

ETP and Regency rely on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines, and Regency maintains contracts for compression services with a limited number of key customers. The failure of the major shippers on ETP’s, Regency’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP, Regency or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

Our interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

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.

We are required to file tariff rates (also known as recourse rates) with FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. We must also file with FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. FERC must approve or accept all rate filings for us to be allowed to charge such rates.

FERC may review existing tariffs rates own initiative or upon receipt of a complaint filed by a third party. FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. FERC has recently exercised this authority with respect to several other pipeline companies, as it had in 2007 with respect to our Southwest Gas. If FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay us may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of our interstate pipeline operations may increase and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by FERC or third parties, and FERC may deny, modify or limit our proposed changes if we are unable to persuade FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for, and obtain rate increases, our operating results would be negatively

 

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affected. Even if a rate increase is permitted by FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

In 2010, in response to an intervention and protest filed by BG LNG Services (BGLS) regarding its rates with Trunkline LNG applicable to certain LNG expansions, FERC determined that there was no reason at that time to expend FERC’s resources on a rate proceeding with respect to Trunkline LNG even though cost and revenue studies provided by the Company to FERC indicated Trunkline LNG’s revenues were in excess of its associated cost of service. However, since the current fixed rates expire at the end of 2015 and revert to tariff rate for these LNG expansions as well as the base LNG facilities for which rates were set in 2002, a rate proceeding could be initiated at that time and result in significant revenue reductions if the cost of service remains lower than revenues.

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 that 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.

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 effectiveness of FERC’s policy and the application of that policy remains subject to future challenges, refinement or change by FERC or the courts. 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 ETP’s and Regency’s interstate pipelines, including:

 

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operating terms and conditions of service;

 

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the types of services interstate pipelines may or must 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, policies and interpretations thereof in these areas may impair the ability of ETP’s and Regency’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

 

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ETP and Regency must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of their business plans. For example, in order to carry out its plan to construct the Fayetteville Express and Tiger pipelines ETP was 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. ETP and Regency cannot guarantee that FERC will authorize construction and operation of any future interstate natural gas transportation project it might propose. ETP and Regency are required to attain approval from FERC for expansions of their pipeline facilities. ETP cannot guarantee that FERC will authorize any future interstate natural gas transportation project ETP might propose. Moreover, there is no guarantee that certificate authority for interstate projects will be granted in a timely manner or without being subject to potentially burdensome conditions. We may also begin to construct a new facility or provide a new service based on a FERC authorization that is subsequently overturned or modified after review by a court. This could have a material adverse effect on the costs of and revenues of the new facility or service

Similarly, MEP was required to obtain from FERC a certificate of public convenience and necessity to build, own and operate the Midcontinent Express pipeline. Although the FERC has granted such certificate authority, the FERC’s certificate order is currently pending judicial review before the United States Court of Appeals for the District of Columbia Circuit. ETP and Regency cannot give any assurance that the court will affirm, in all material respects, the FERC’s July 25, 2008 Midcontinent Express certificate order, or that the FERC will not materially alter the certificate order on any remand that might be ordered by the court. There are also pending requests for rehearing related to certain of the FERC’s post-certification orders related to the Midcontinent Express project. ETP and Regency cannot guarantee that these post-certification orders will not be altered on rehearing or that these orders will not be subject to judicial review.

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 million per day for each violation. FERC possesses similar authority under the NGPA.

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

Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil and refined products pipeline operations.

Our common carrier interstate crude oil and refined products pipelines are subject to rate regulation by FERC, which requires that tariff rates for these oil pipelines be just and reasonable and not unduly discriminatory. FERC or interested persons may challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

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

 

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methodology changes, the new methodology could materially and adversely affect our 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 our 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 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, FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.

If FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

Should we violate laws and regulations prohibiting market manipulation, we could be subject to substantial fines and penalties and lose the governmental authorizations needed conduct our businesses.

The Energy Policy Act of 2005 amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets. FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. FERC is authorized to impose civil penalties of up to $1 million per day per violation and grant other relief, such as ordering refunds, or revoking operating authority.

Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued a rule that prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. The FTC rule also bans intentional failures to state a material fact when the omission makes a statement misleading and distorts, or is likely to distort, market conditions for any product covered by the rule. The FTC holds substantial enforcement authority under the EISA, including authority to request that a court impose fines of up to $1 million per day per violation. FERC may also order reparations and suspend tariffs for violations of the ICA in connection with interstate oil pipeline transportation.

Under the Commodity Exchange Act, the CFTC is directed to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to assess fines of up to $1,000,000 or triple the monetary gain for violations of its anti-market manipulation regulations.

State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage 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 service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

 

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Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be adversely affected.

Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

Certain of ETP’s and Regency’s 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 ETP and Regency acquired as part of the LDH acquisition, transports NGLs within the state of Texas and is subject to regulation by the Texas Railroad Commission (“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. ETP and Regency 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 ETP or Regency 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.

We are subject to extensive federal and state pipeline safety regulation, including integrity management requirements, which may adversely affect our costs and operations.

Our pipeline operations are subject to regulation by the DOT, under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, 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 $7 million and operating and maintenance costs of $15 million over the course of the next year. For the years ended December 31, 2012, 2011 and 2010, $7 million, $18.3 million and $13.3 million, respectively, of capital costs and $17 million, $14.7 million and $15.4 million, respectively, of operating and maintenance costs have been

 

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incurred for pipeline integrity testing. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. 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.

Federal pipeline safety regulation is also becoming increasingly stringent and additional laws and regulations are being considered. The recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, 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.

On August 13, 2012, PHMSA published rules to update pipeline safety regulations to reflect provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties and changing PHMSA’s enforcement process. PHMSA has also published advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations for oil and gas pipelines, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines.

Further, additional laws, regulations and policies that may be enacted or adopted in the future or a new interpretation of existing laws and regulations could significantly increase the cost of complying with safety laws and regulations. For example, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs or result in reductions of allowable operating pressures, which would reduce available pipeline capacity. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines, but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt.

 

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Should we violate federal or state health and safety laws and regulations, we could be subject to substantial criminal, civil and administrative penalties and other relief, as well as potential liabilities to third parties.

Our natural gas distribution operations subject us to risks that could have a material adverse effect on our business, results of operations, cash flows and financial condition.

On December 17, 2012, Southern Union entered into definitive purchase and sale agreements with subsidiaries of the Laclede Group, Inc. to sell the assets of its Missouri Gas Energy and New England Gas Company Divisions. Until the transaction is consummated, we will be subject to various risks relating to our natural gas distribution operations, including the following:

 

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our ability to achieve timely and effective rate relief from state regulators;

 

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our ability to achieve timely and effective rate relief from state regulators;

 

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the impact of fluctuations in natural gas prices;

 

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the inability to recover from customers certain assets recorded on our balance sheet;

 

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adverse weather conditions;

 

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operational risks, including accidents, the breakdown or failure of equipment or processes, the failure of suppliers’ processing facilities to perform at expected levels of capacity or efficiency and the collision of equipment with facilities; and

 

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catastrophic events, including explosions, fires, earthquakes, floods, landslides, tornadoes, lightning or other similar events.

ETP’s and Regency’s businesses involve hazardous substances and may be adversely affected by environmental regulation.

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

ETP and Regency may incur substantial environmental costs and liabilities because of the underlying risk inherent to its 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 ETP or Regency may have sent wastes or on, under, or from ETP’s and Regency’s current or former properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by ETP’s and Regency’s respective predecessors. Private parties, including the owners of properties through which ETP’s and Regency’s pipelines or gathering systems pass or facilities where their petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation liabilities. Environmental laws also authorize government agencies, in some circumstance, to seek compensation for natural resource damages as an adjunct to remediation

 

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programs. If such natural resource damages claims are brought against us, our liability associated with any such sites could substantially increase. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

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

Product liability claims and litigation could adversely affect our 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. There can be no assurance that product liability claims against us would not have a material adverse effect on our 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 (“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 our business or results of operations.

Recently proposed 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 issued final rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing by January 2015, 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 proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. These rules will require us to modify certain of our operations, including the possible installation of new equipment. Compliance with such rules will be required within three years of their effective date, and it could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

 

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Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, NGLs, crude oil and refined products that ETP and Regency transport, store or otherwise handle.

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 has recently adopted 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 another which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. In November 2011, the EPA also adopted rules requiring companies with facilities that emit over 25,000 metric tons or more of carbon dioxide to report their greenhouse gas emissions to the EPA by September 30, 2012, a requirement with which we timely complied.

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 may be reduced over time 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 ETP or Regency 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, NGLs, crude oil and refined products. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on ETP’s or Regency’s businesses, financial conditions and results of operations.

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, the operations of ETP and Regency could be adversely affected in various ways, including damages to their 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 ETP’s and Regency’s fuel 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 ETP and Regency 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 ETP’s and Regency’s 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 the business of ETP and Regency.

The adoption of the Dodd -Frank Act 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, resulting in our operations becoming more volatile and our cash flows less predictable.

Congress has adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), a comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation was signed into law by President Obama on July 21, 2010 and requires the U.S. Commodities Futures Trading Commission

 

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(the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC and the SEC as a result of their activities in the derivatives markets or otherwise become specifically qualified to enter into derivatives contracts. We will be required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.

Reporting and recordkeeping requirements also could significantly increase operating costs and expose us to penalties for non-compliance. Certain CFTC recordkeeping requirements became effective on October 14, 2010, and additional recordkeeping requirements will be phased in through April 2013. Beginning on December 31, 2012, certain CFTC reporting rules became effective, and additional reporting requirements will be phased in through April 2013. These additional recordkeeping and reporting requirements may require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices and our ability to hedge.

The CFTC has also issued 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 were to become effective on October 12, 2012, but a United States District Court vacated and remanded the position limits rules to the CFTC. The CFTC has appealed that ruling and it is uncertain at this time whether, when, and to what extent the CFTC’s position limits rules will become effective.

The new regulations may also require us to comply with certain margin requirements for our over-the counter derivative contracts with certain CFTC- or SEC-registered entities that could require us to enter into credit support documentation and/or post significant amounts of cash collateral, which could adversely affect our liquidity and ability to use derivatives to hedge our commercial price risk; however, the proposed margin rules are not yet final and therefore 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 also requires that certain derivative instruments be centrally cleared and executed through an exchange or other approved trading platform. Mandatory exchange trading and clearing requirements could result in increased costs in the form of additional margin requirements imposed by clearing organizations. On December 13, 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although there may be an exception to the mandatory exchange trading and clearing requirement that applies to our trading activities, we must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on this exception. In addition, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.

Rules promulgated under the Dodd-Frank Act further defined forwards as well as instances where forwards may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC’s rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.

 

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The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through restrictions on the types of collateral we are required to post), 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 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. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s and Regency’s operations and otherwise materially adversely affect their cash flow.

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

If one or more facilities that are owned by ETP or Regency or that deliver natural gas or other products to ETP or Regency are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s or Regency’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s or Regency’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s or Regency’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s or Regency’s cash available for paying distributions to its Unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP and Regency may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP or Regency were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s or Regency’s financial position and results of operations, as applicable. 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 its business, results of operations, cash flows and financial condition.

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Regency’s facilities or pipelines or those of its customers could have a material adverse effect on ETP’s or Regency’s business, as applicable.

 

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ETP has a significant equity investment in AmeriGas and the value of this investment, and the cash distributions ETP expects to receive from this investment, are subject to the risks encountered by AmeriGas with respect to its business.

In January 2012, ETP consummated the contribution of its 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 HOLP debt. The value of ETP’s investment in AmeriGas common units and the cash distributions it expects 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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increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand;

 

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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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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.

 

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We are subject to risks resulting from the moratorium in 2010 on and the resulting increased costs of offshore deepwater drilling.

The United States Department of Interior (the “DOI”) implemented a six-month moratorium on offshore drilling in water deeper than 500 feet in response to the Macondo accident and oil spill in the U.S. Gulf of Mexico. The offshore drilling moratorium was implemented to permit the DOI to review the safety protocols and procedures used by offshore drilling companies, which review will enable the DOI to recommend enhanced safety and training needs for offshore drilling companies. The moratorium was lifted in October 2010. The United States Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement (formerly the Bureau of Ocean Energy Management, Regulation and Enforcement) have enacted enhanced regulatory mandates with additional regulatory mandates expected. The new regulatory requirements will increase the cost of offshore drilling and production operations. The increased regulations and cost of drilling operations could result in decreased drilling activity in the areas serviced by Southern Union. Furthermore, the imposed moratorium did result in some offshore drilling companies relocating their offshore drilling operations for currently indeterminable periods of time to regions outside of the United States. Business decisions to not drill in the areas serviced by Southern Union resulting from the increased regulations and costs could result in a reduction in the future development and production of natural gas reserves in the vicinity of Southern Union’s facilities, which could adversely affect our business, financial condition, results of operations and cash flows.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport through Sunoco Logistics’ operations are sold by our 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 our throughput volume, require us 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 our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending services licenses.

Our business could be affected adversely by union disputes and strikes or work stoppages by Southern Union’s and Sunoco’s unionized employees.

As of December 31, 2012, approximately 37%, 45% and 7% of Southern Union’s, Sunoco Logistics’ and Sunoco’s workforce, respectively, were covered by a number of collective bargaining agreements with various terms and dates of expirations. There can be no assurances that Southern Union or Sunoco will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.

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 us to incur additional capital expenditures or expenses particularly in our retail marketing business.

 

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We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We 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 we supply. 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 we market and sell.

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.

We have outsourced various functions related to our retail marketing business to third-party service providers, which decreases our control over the performance of these functions. Disruptions or delays of our third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

Sunoco has previously outsourced various functions related to our retail marketing business to third parties and expects to continue this practice with other functions in the future.

While outsourcing arrangements may lower our cost of operations, they also reduce our 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 our ability to quickly respond to changing market conditions, or on our ability to ensure compliance with all applicable domestic and foreign laws and regulations. We believe that we conduct appropriate due diligence before entering into agreements with our outsourcing partners. We rely on our outsourcing partners to provide services on a timely and effective basis. Although we continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, we do not ultimately control the performance of our outsourcing partners. Much of our outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of our third-party outsourcing partners to provide the expected services on a timely basis at the prices we expect, 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 our operations, which could materially adversely affect our business, financial condition, operating results and cash flow.

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

As a result of these outsourcing initiatives, more third parties are involved in processing our retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about our retail marketing business or

 

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our clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss or misuse of this information, result in litigation and potential liability for us, lead to reputational damage to the Sunoco brand, increase our compliance costs, or otherwise harm our business.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process 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, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have 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. Our business interruption insurance may not compensate us adequately for losses that may occur.

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

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our 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 our 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 for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results. In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for employees.

Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. In addition, the passage of the Health Care Reform Act of 2010 could significantly increase the cost of health care benefits for our employees. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

 

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Regency’s contract compression operations depend on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on its results of operations.

The principal manufacturers of components for Regency’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Regency’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. Regency also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. Regency does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on Regency’s results of operations and could damage its customer relationships. In addition, since Regency expects any increase in component prices for compression equipment or packaging costs will be passed on to Regency, a significant increase in their pricing could have a negative impact on Regency’s results of operations.

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

Despite the fact that we, ETP and Regency are each 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. If ETP or Regency were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to us. As a result, there would be a material reduction in the anticipated cash flow. In either case, our available cash would be substantially reduced.

The present tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time, causing us or our subsidiaries to be treated as a corporation for federal income tax purposes or otherwise subjecting us or our subsidiaries to entity-level taxation. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the U.S. federal income tax laws that affect the tax treatment of 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 or our subsidiaries 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 be reintroduced or will ultimately be enacted, any such changes could substantially reduce the amount of cash available to us to meet our obligations, including obligations under the notes.

 

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USE OF PROCEEDS

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

We intend to use the net proceeds from this offering, together with the net proceeds from our new term loan credit facility, to fund the Tender Offer, including any related fees, expenses and accrued interest. Several of the underwriters may participate and tender notes owned by such institutions in the Tender Offer and thereby receive a portion of the proceeds of this offering. To the extent the net proceeds from this offering exceed the purchase price for the amount of the 2020 Notes tendered in the Tender Offer and the related fees, expenses and accrued interest, we intend to use the balance for general partnership purposes.

As of November 11, 2013, an aggregate of $1.8 billion principal amount of the 2020 Notes were outstanding. The 2020 Notes mature on October 15, 2020. See “Description of Other Indebtedness—Energy Transfer Equity, L.P.—Senior Notes.”

 

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CAPITALIZATION

The following table sets forth our consolidated cash and cash equivalents and our consolidated capitalization as of September 30, 2013 on:

 

•

an actual basis; and

 

•

an as adjusted basis to give effect to (i) the Tender Offer, assuming an aggregate of $400 million principal amount of the 2020 Notes are validly tendered and accepted for purchase; (ii) the entry into our new revolving credit facility and new term loan facility; and (iii) the notes offered hereby and the application of the estimated net proceeds of this offering as described in “Use of Proceeds.”

The actual information in the table is derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, included in this prospectus supplement. The amounts in the table below are in millions.

 

		September 30, 2013
		Actual				As Adjusted
Cash and Cash Equivalents		$	1,177			$	1,187
Long-Term Debt:
Debt of Energy Transfer Equity
Existing Revolving Credit Facility(1)		$	—			$	—
New Revolving Credit Facility(1)			—				—
Existing Term Loan Facility(2)			900				—
New Term Loan Facility(2)			—				1,000
7.500% Senior Notes due 2020(3)			1,800				1,400
Notes offered hereby			—
Debt of Energy Transfer Partners
ETP Revolving Credit Facility(4)			—				—
ETP Senior Notes		$	10,636			$	10,636
ETP Junior Subordinated Notes			546				546
Transwestern Senior Notes			870				870
Sunoco Senior Notes			965				965
Southern Union Senior Notes			116				116
Southern Union Junior Subordinated Notes			54				54
Panhandle Senior Notes			916				916
Sunoco Logistics Credit Facilities(5)			35				35
Sunoco Logistics Senior Notes			2,150				2,150
Debt of Regency Energy Partners
Revolving Credit Facility(6)			176				176
Senior Notes			2,800				2,800
Other long-term debt			46				46
Unamortized premiums and fair value adjustments, net			299				299
Total Long-Term Debt			22,309
Total Equity(7)		$	17,204			$
Total Capitalization		$	39,513			$

 

(1)

As of November 11, 2013, we had no borrowings outstanding under our existing revolving credit facility. In conjunction with the closing of this offering, we expect to refinance our existing revolving credit facility and expect to have no borrowings outstanding under our new revolving credit facility at such time and $600 million of availability thereunder. There can be no assurance that we will successfully refinance our existing revolving credit facility. Please see “Description of Other Indebtedness—Energy Transfer Equity, L.P.—New Revolving Credit Facility.”

 

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(2)

In conjunction with the closing of this offering, we expect to refinance our existing term loan facility and expect to have $1.0 billion of borrowings outstanding under our new term loan facility at such time. There can be no assurance that we will successfully refinance our existing term loan facility. Please see “Description of Other Indebtedness—Energy Transfer Equity, L.P.—New Term Loan Facility.”

(3)

Assumes that an aggregate of $400 million principal amount of the 2020 Notes are validly tendered and accepted for purchase in the Tender Offer at a purchase price of approximately $460 million, including related fees, expenses and accrued interest. The actual amount of 2020 Notes validly tendered and accepted for purchase may be less or, if we elect to increase the Tender Cap prior to the Expiration Time, may be more. We cannot assure you that the Tender Offer will be consummated in accordance with its terms, or at all. For a discussion of the terms of the 2020 Notes, please see “Description of Other Indebtedness—Energy Transfer Equity, L.P.—Senior Notes.”

(4)	As of November 11, 2013, ETP had no borrowings outstanding under its revolving credit facility and had $2.4 billion of availability thereunder.

(5)	As of November 11, 2013, Sunoco Logistics and its subsidiaries had an aggregate of $35 million of borrowings outstanding under their credit facilities and $550 million of availability thereunder.

(6)	As of November 11, 2013, Regency had $321 million of borrowings outstanding under its revolving credit facility and $879 million of availability thereunder.

In addition to the amounts shown above, as of November 11, 2013, ETP’s unconsolidated joint ventures, FEP, Citrus and FGT, had an aggregate of $3.1 billion of indebtedness outstanding and Regency’s unconsolidated joint ventures, HPC, MEP, Lone Star and Ranch JV, had an aggregate of $438 million of indebtedness outstanding. In connection with the closing of the contribution of ETP’s propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022. Similarly, in connection with the closing of the SUGS Contribution in April 2013, PEPL Holdings, a subsidiary of Southern Union, agreed to provide a guarantee of collection (on a nonrecourse basis) on $600 million of senior notes issued by Regency and its affiliate with maturity in 2023.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected historical consolidated financial data as of the dates and for the periods presented. The selected historical consolidated financial data as of and for each of the years in the three year period ended December 31, 2012 are derived from our audited consolidated financial statements included in this prospectus supplement. The selected historical consolidated financial data as of September 30, 2013 and for the nine months ended September 30, 2013 and September 30, 2012 are derived from our unaudited consolidated financial statements included in this prospectus supplement, which, in the opinion of management, include all adjustments necessary for a fair presentation of our financial position as of such dates and our results of operations for such periods. The selected historical consolidated balance sheet data as of September 30, 2012, December 31, 2010, 2009 and 2008, as well as the selected historical consolidated statement of operations and cash flow data for the years ended December 31, 2009 and 2008 are derived from our financial statements not incorporated by reference into this prospectus supplement. Nine month results, however, are not necessarily indicative of the results that may be expected for any other interim period or for a full fiscal year.

The selected historical financial data should be read in conjunction with our historical consolidated financial statements and the notes thereto included in this prospectus supplement, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Capitalization.” The amounts in the tables below are in thousands.

 

		Nine Months Ended September 31,								Years Ended December 31,
		2013				2012				2012				2011				2010				2009				2008
Statement of Operations Data:
Total revenues		$	35,728			$	5,651			$	16,964			$	8,190			$	6,556			$	5,378			$	9,236
Operating income		$	1,704			$	908			$	1,360			$	1,237			$	1,044			$	1,047			$	1,079
Income from continuing operations		$	972			$	1,138			$	1,383			$	531			$	345			$	692			$	675
Basic income from continuing operations per limited partner unit		$	1.24			$	1.06			$	1.17			$	1.39			$	0.87			$	1.97			$	1.67
Diluted income from continuing operations per limited partner unit		$	1.24			$	1.06			$	1.17			$	1.38			$	0.87			$	1.97			$	1.67
Cash distribution per unit		$	2.69			$	2.50			$	2.51			$	2.44			$	2.16			$	2.14			$	1.91
Balance Sheet Data (at period end):
Total assets		$	50,043			$	33,598			$	48,904			$	20,897			$	17,379			$	12,161			$	11,070
Long-term debt, less current maturities		$	22,011			$	17,526			$	21,440			$	10,947			$	9,346			$	7,751			$	7,190
Total equity		$	17,204			$	10,691			$	16,350			$	7,388			$	6,248			$	3,220			$	2,339

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto incorporated by reference from our Quarterly Report on Form 10-Q for the quarter ended September 30, 2013 filed with the SEC on November 7, 2013, our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 1, 2013 and our Current Report on Form 8-K filed with the SEC on November 14, 2013. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Risk Factors,” included in this prospectus supplement.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, and Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. All tabular dollar amounts in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are in millions.

Overview

We directly and indirectly own equity interests in ETP and Regency, both of which are publicly-traded master limited partnerships engaged in diversified energy-related services. At October 31, 2013, our interest in ETP and Regency consisted of:

 

		ETP				Regency
General Partner interest			0.8	%			1.3	%
IDRs			100	%			100	%
Units held by wholly owned subsidiaries (in millions):
Common units			49.6				26.3
ETP Class H units			50.2				—
Units held by less than wholly owned subsidiaries (in millions):
Common units			—				31.4
Regency Class F units			—				6.3

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency, both of which are publicly traded master limited partnerships engaged in diversified energy-related services. The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Preferred Units, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.

As a result of the Regency Transactions in May 2010, the Southern Union Merger in March 2012 and the Sunoco Merger in October 2012, the periods presented herein do not include activities from Regency, Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

 

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Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and NGL businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.

As a result of the Holdco Acquisition in April 2013, our reportable segments were re-evaluated and currently reflect the following reportable segments:

 

•

Investment in ETP, including the consolidated operations of ETP.

 

•

Investment in Regency, including the consolidated operations of Regency.

 

•

Corporate and Other, including the following:

 

•

activities of the Parent Company; and

 

•

the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. ETP also controls ETP Holdco Corporation.

Recent Developments

On January 12, 2012, ETP Contributed its propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.

On March 26, 2012, we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57 million ETE Common Units. In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT.

The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units.

On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and approximately $2.6 billion in cash.

Immediately following the closing of the Sunoco merger, ETE contributed its interest in Southern Union into ETP Holdco Corporation, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco to ETP Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 ETP Class F Units representing limited partner interests in ETP. We refer to this as the “Holdco Transaction.” Pursuant to a stockholders agreement between ETE and ETP, ETP controls ETP Holdco. Consequently, ETP consolidates ETP

 

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Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. As a result, ETP now owns 100% of ETP Holdco.

In December 2012, Southern Union entered into a purchase and sale agreement pursuant to which subsidiaries of Laclede Gas Company, Inc. have agreed to acquire the assets of Southern Union’s Missouri Gas Energy and New England Gas Company divisions. Total consideration for the acquisitions will be $1.035 billion, subject to customary closing adjustments, less the assumption of approximately $19 million of debt. On February 11, 2013, the Laclede Entities announced that it had entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that will allow a subsidiary of APUC to assume the right of the Laclede Entities to purchase the assets of Southern Union’s New England Gas Company division, subject to certain approvals. It is expected that the transactions contemplated by the Purchase and Sale Agreements will close by the end of the third quarter of 2013.

Effective September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. The sale of Southern Union’s NEG division is expected to close in the fourth quarter of 2013 for cash proceeds of $40 million, subject to customary post-closing adjustments and the assumption of $20 million of debt.

On February 27, 2013, Southern Union entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to Southern Union, (ii) the issuance of 6,274,483 Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. Upon the closing of the transaction, we will agree to forego all distributions with respect to our IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing. The transaction closed in the second quarter of 2013.

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes. The fair value on the settlement date of the 7.6% Senior Notes due 2024, the 8.25% Senior Notes due 2029 and the Junior Subordinated Notes due 2066 was $328 million, $328 million and $464 million, respectively, which represented 118.16%, 122.84% and 85%, respectively, of the outstanding principal amount of the notes.

On July 12, 2013, ETP received $346 million in net proceeds from the sale of 7.5 million of its AmeriGas common units, which were received in connection with ETP’s contribution of its retail propane operations to AmeriGas in January 2012. Net proceeds from this sale were used to repay borrowings under the ETP Credit Facility.

 

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Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its common units representing limited partner interests owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of the new Class H Units of limited partner interest in ETP which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners, the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental cash distributions in the aggregate amount of $329 million to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Cash Distributions” below.

ETP agreed to make incremental cash distributions of $329 million discussed above as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. As a result, the net IDR subsidies from ETE to ETP, taking into account the incremental cash distributions related to the Class H Units as an offset thereto, were $21 million for the quarter ended September 30, 2013 and will be $21 million with respect to the quarter ending December 31, 2013, a total of $109 million during 2014, a total of $53 million during 2015 and a total of $22 million during 2016.

On August 7, 2013, Lake Charles Exports, LLC, an entity owned by BG Group and Trunkline LNG Export, LLC (a joint venture owned by ETP and ETE), received an order from the Department of Energy conditionally granting authorization to export up to 15 million metric tonnes per annum of LNG to non-free trade agreement countries from the existing LNG import terminal owned by Trunkline LNG Company, LLC (an indirect wholly-owned subsidiary of ETP), which is located in Lake Charles, Louisiana. Lake Charles Exports, LLC previously received approval to export LNG from the Lake Charles facility to free trade agreement countries on July 22, 2011. In October 2013, ETE, ETP and BG Group announced their entry into a project development agreement to jointly develop the LNG export project at the existing Trunkline LNG import terminal in Lake Charles, Louisiana.

On October 10, 2013, Regency and PVR Partners, L.P. (“PVR”) announced the approval of a merger agreement, pursuant to which Regency intends to propose to acquire PVR. This acquisition will be a unit-for-unit transaction plus a one-time $40 million cash payment to PVR unitholders which represents total consideration of $5.6 billion, including the assumption of net debt of $1.8 billion. The holders of PVR common units, PVR Class B Units and PVR Special Units (“PVR Unit(s)”) will receive 1.02 Regency common units in exchange for each PVR Unit held on the applicable record date. The transaction is subject to the approval of PVR’s unitholders, Hart-Scott-Rodino Antitrust Improvements Act approval and other customary closing conditions. The transaction is expected to close in the first quarter of 2014.

In October 2013, La Grange Acquisition, L.P., an indirect wholly-owned subsidiary of ETP, acquired a convenience store operator with a network of approximately 300 company-owned and dealer locations for approximately $400 million in cash. These operations will be reflected in ETP’s retail marketing segment, along with the retail marketing operations owned by Holdco, beginning in the fourth quarter of 2013.

As we and our subsidiaries have completed several major strategic transactions since 2011 to expand our midstream service capabilities and to geographically diversity our asset platform, our focus is currently on the

 

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full integration and optimization of our diversified asset portfolio to enhance unitholder value. We expect to simplify our organization during 2013 and 2014 and possibly beyond. In order to take advantage of numerous asset optimization opportunities, we may consider potential transactions among us and our subsidiaries and/or affiliates.

In addition, we expect to benefit from continued growth among our existing consolidated subsidiaries. Aggregate growth capital expenditures among our consolidated subsidiaries totaled $3.52 billion in 2012, and we expect that amount to be approximately $2.6 billion in 2013. Our announced growth projects include a second fractionator at Mont Belvieu and expansion in the Eagle Ford Shale and Permian Basin. Along with the inherent benefits of greater scale and cash flow diversification that we experience from growth projects, we also expect to benefit in 2013 from the full-year impacts of the recent Southern Union and Sunoco acquisitions as well as additional synergies that may be created as we continue to streamline the organization.

Results of Operations

We previously reported net income as a measure of segment performance. We have revised certain reports provided to our chief operating decision maker to assess the performance of our business to reflect Segment Adjusted EBITDA. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.

ETP contributed SUGS to Regency on April 30, 2013. This transaction between commonly controlled entities was accounted for by Regency in a manner similar to the pooling of interests method of accounting. Under this method of accounting, Regency reflected historical balance sheet data for SUGS instead of reflecting the fair value of the SUGS assets and liabilities from the date of acquisition forward. Regency retrospectively adjusted its financial statements to include the operations of SUGS from March 26, 2012 (the date upon which common control began), and accordingly, such retrospectively adjusted amounts are reflected herein for Regency.

Based on the change in our segment performance measure, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 2 of our unaudited consolidated financial statements included in this prospectus supplement, Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.

 

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Nine Months Ended September 30, 2013 Compared to the Nine Months Ended 2012

Consolidated Results

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2013				2012				Change				2013				2012				Change
Segment Adjusted EBITDA:
Investment in ETP		$	942			$	660			$	282			$	2,967			$	1,796			$	1,171
Investment in Regency			172				141				31				446				398				48
Corporate and Other			(9	)			(7	)			(2	)			(38	)			(48	)			10
Adjustments and Eliminations(1)			(56	)			(40	)			(16	)			(111	)			(83	)			(28	)
Total			1,049				754				295				3,264				2,063				1,201
Depreciation and amortization			(332	)			(211	)			(121	)			(962	)			(571	)			(391	)
Interest expense, net of interest capitalized			(298	)			(237	)			(61	)			(913	)			(732	)			(181	)
Bridge loan related fees			—				—				—				—				(62	)			62
Gain on deconsolidation of Propane Business			—				—				—				—				1,057				(1,057	)
Gain on sale of AmeriGas common units			87				—				87				87				—				87
Gains (losses) on interest rate derivatives			3				(6	)			9				55				(23	)			78
Non-cash unit-based compensation expense			(16	)			(10	)			(6	)			(43	)			(34	)			(9	)
Unrealized gains (losses) on commodity risk management activities			22				4				18				45				(43	)			88
Losses on extinguishment of debt			—				—				—				(7	)			(123	)			116
Gain on curtailment of other postretirement benefit plans			—				—				—				—				15				(15	)
LIFO valuation adjustments			6				—				6				22				—				22
Equity in earnings of unconsolidated affiliates			38				21				17				182				118				64
Adjusted EBITDA related to unconsolidated affiliates			(165	)			(148	)			(17	)			(553	)			(429	)			(124	)
Adjusted EBITDA related to discontinued operations			(12	)			(32	)			20				(75	)			(66	)			(9	)
Other, net			10				(1	)			11				6				1				5
Income from continuing operations before income tax expense			392				134				258				1,108				1,171				(63	)
Income tax expense from continuing operations			49				26				23				136				33				103
Income from continuing operations			343				108				235				972				1,138				(166	)
Income (loss) from discontinued operations			13				(142	)			155				44				(136	)			180
Net income		$	356			$	(34	)		$	390			$	1,016			$	1,002			$	14

 

(1)	See description of eliminations included in Note 18 to our unaudited consolidated financial statements included in this prospectus supplement.

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation and Amortization. Depreciation and amortization for the three months ended September 30, 2013 increased primarily due to the following:

 

•

depreciation and amortization related to Sunoco Logistics and Sunoco of $95 million; and

 

•

additional depreciation and amortization related to assets placed in service.

Depreciation and amortization for the nine months ended September 30, 2013 increased primarily due to the following:

 

•

depreciation and amortization related to Sunoco Logistics and Sunoco of $277 million;

 

•

depreciation and amortization related to Southern Union and SUGS, which were acquired on March 26, 2012, and resulted in increased depreciation and amortization of $41 million in the aggregate; and

 

•

additional depreciation and amortization related to assets placed in service.

 

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Interest Expense, Net of Interest Capitalized. Interest expense for the three months ended September 30, 2013 increased primarily due to the following:

 

•

interest expense related to Sunoco Logistics and Sunoco of $30 million;

 

•

incremental interest expense due to ETP’s issuance of $1.25 billion of senior notes in January 2013 and $1.5 billion of senior notes in September 2013; and

 

•

incremental interest expense due to Regency’s issuance of $700 million of senior notes in October 2012, $600 million of senior notes in April 2013 and $400 million of senior notes in September 2013; partially offset by

 

•

a reduction of $17 million for the Parent Company primarily related to a $1.1 billion principal paydown of the Parent Company’s $2 billion term loan in April 2013.

Interest expense for the nine months ended September 30, 2013 increased primarily due to the following:

 

•

interest expense related to Sunoco Logistics and Sunoco of $83 million;

 

•

incremental interest expense due to ETP’s issuance of $1.25 billion of senior notes in January 2013 and $1.5 billion of senior notes in September 2013; and

 

•

an increase of $33 million related to Regency primarily due to its issuance of $700 million of senior notes in October 2012, $600 million of senior notes in April 2013 and $400 million of senior notes in September 2013; partially offset by

 

•

a reduction of $6 million for the Parent Company primarily related to a $1.1 billion principal paydown of the Parent Company’s $2 billion term loan in April 2013; and

 

•

a reduction of several series of ETP’s higher coupon notes that were repurchased in the tender offers completed in January 2012.

Bridge Loan Related Fees. The bridge loan commitment fee recognized during the nine months ended September 30, 2012 was incurred in connection with our merger with Southern Union (the “Southern Union Merger”). The Parent Company obtained permanent financing for the transaction through a $2 billion senior secured term loan which was funded upon closing of the Southern Union Merger on March 26, 2012.

Gain on Deconsolidation of Propane Business. ETP recognized a gain on deconsolidation related to the contribution of its propane business (the “Propane Business”) operated through its former subsidiaries, Heritage Operating, L.P. and Titan Energy Partners, L.P., to AmeriGas in January 2012 (such transaction referred to as the “Propane Transaction”).

Gains (Losses) on Interest Rate Derivatives. Gains on interest rate derivatives during the three and nine months ended September 30, 2013 resulted from increases in forward interest rates, which caused our forward-starting swaps to increase in value. These swaps are marked to fair value for accounting purposes with changes in value recorded in earnings each period. Conversely, decreases in forward interest rates resulted in losses on interest rate derivatives during the three and nine months ended September 30, 2012.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Losses on Extinguishment of Debt. ETP recognized a loss on extinguishment of debt in connection with its repurchase of $750 million of senior notes in January 2012. In addition, Regency recognized a $7 million loss on extinguishment of debt in connection with its repurchase of senior notes in June 2013 and $8 million in connection with its repurchase of senior notes in May 2012.

 

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LIFO Valuation Adjustments. LIFO valuation reserve adjustments were recorded for the inventory associated with Sunoco’s retail marketing operations as a result of commodity price changes between periods.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to AmeriGas, FEP, HPC and MEP, as well as Citrus beginning March 26, 2012. The 2013 amounts also include our proportionate share of Philadelphia Energy Solutions (“PES”).

Adjusted EBITDA Related to Discontinued Operations. Amounts reflect the operations of ETC Canyon Pipeline, LLC (“Canyon”), which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

Other, net. Includes amortization of regulatory assets and other income and expense amounts.

Income Tax Expense. Income tax expense increased primarily due to the acquisitions of Southern Union and Sunoco, both of which are taxable corporations.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of ETE has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the Propane Transaction, the Sunoco Merger and the Holdco Transaction for the nine months ended September 30, 2012, giving effect to each such transaction as if it occurred on January 1, 2012. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Propane Transaction, the Sunoco Merger and the Holdco Transaction had been consummated on January 1, 2012.

 

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The following table presents the pro forma financial information for the nine months ended September 30, 2012:

 

		ETE Historical				Propane Transaction(a)				Sunoco Historical(b)				Southern Union Historical(c)				Holdco Pro Forma Adjustments(d)				Pro Forma
Revenues		$	5,651			$	(93	)		$	35,258			$	443			$	(12,175	)		$	29,084
Costs and Expenses:
Cost of products sold and natural gas operations			3,819				(80	)			33,142				313				(11,189	)			26,005
Depreciation and amortization			571				(4	)			168				49				73				857
Selling, general and administrative			353				(1	)			459				—				(69	)			742
Impairment charges			—				—				124				—				(22	)			102
Total costs and expenses			4,743				(85	)			33,893				362				(11,207	)			27,706
Operating Income			908				(8	)			1,365				81				(968	)			1,378
Other Income (Expense):
Interest expense, net of interest capitalized			(794	)			2				(123	)			(50	)			6				(959	)
Equity in earnings of affiliates			118				3				41				16				21				199
Gain on deconsolidation of Propane Business			1,057				(1,057	)			—				—				—				—
Gain on formation of PES			—				—				1,144				—				(1,144	)			—
Gain (loss) on disposal of assets			—				2				112				—				(2	)			112
Loss on extinguishment of debt			(123	)			115				—				—				—				(8	)
Losses on interest rate derivatives			(23	)			—				—				—				—				(23	)
Other, net			28				1				6				(2	)			—				33
Income From Continuing Operations Before Income Tax Expense			1,171				(942	)			2,545				45				(2,087	)			732
Income tax expense from continuing operations			33				—				956				12				(931	)			70
Income From Continuing Operations		$	1,138			$	(942	)		$	1,589			$	33			$	(1,156	)		$	662

 

(a)	Propane Transaction adjustments reflect the following:

 

•

The adjustments reflect the deconsolidation of ETP’s propane operations in connection with the Propane Transaction.

 

•

The adjustments reflect the pro forma impacts from the consideration received in connection with the Propane Transaction, including ETP’s receipt of AmeriGas common units and ETP’s use of cash proceeds from the transaction to redeem long-term debt.

 

•

The 2012 adjustments include the elimination of (i) the gain recognized by ETP in connection with the deconsolidation of the Propane Business and (ii) ETP’s loss on extinguishment of debt recognized in connection with the use of proceeds to redeem long-term debt.

 

(b)	Sunoco historical amounts in 2012 include the period from January 1, 2012 through September 30, 2012.

 

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(c)	Southern Union historical amounts in 2012 include the period from January 1, 2012 through March 25, 2012.

(d)	Substantially all of the Holdco pro forma adjustments relate to Sunoco’s exit from its Northeast refining operations and formation of the PES joint venture, except for the following:

 

•

The adjustment to depreciation and amortization reflects incremental amounts for estimated fair values recorded in purchase accounting related to Sunoco and Southern Union.

 

•

The adjustment to selling, general and administrative expenses includes the elimination of merger-related costs incurred, because such costs would not have a continuing impact on results of operations.

 

•

The adjustment to interest expense includes incremental amortization of fair value adjustments to debt recorded in purchase accounting.

 

•

The adjustment to equity in earnings of affiliates reflects the reversal of amounts related to Citrus recorded in Southern Union’s historical income statements.

 

•

The adjustment to income tax expense includes the pro forma impact resulting from the pro forma adjustments to pre-tax income of Sunoco and Southern Union.

Segment Operating Results

Investment in ETP

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2013				2012				Change				2013				2012				Change
Revenues		$	11,902			$	1,802			$	10,100			$	34,307			$	4,721			$	29,586
Cost of products sold			10,654				1,026				9,628				30,477				2,606				27,871
Gross margin			1,248				776				472				3,830				2,115				1,715
Unrealized losses (gains) on commodity risk management activities			(8	)			(11	)			3				(45	)			60				(105	)
Operating expenses, excluding non-cash compensation expense			(316	)			(171	)			(145	)			(940	)			(492	)			(448	)
Selling, general and administrative, excluding non-cash compensation expense			(125	)			(71	)			(54	)			(388	)			(255	)			(133	)
LIFO valuation adjustments			(6	)			—				(6	)			(22	)			—				(22	)
Adjusted EBITDA related to unconsolidated affiliates			151				106				45				474				302				172
Adjusted EBITDA related to discontinued operations			12				32				(20	)			75				66				9
Other			—				3				(3	)			(12	)			9				(21	)
Elimination			(14	)			(4	)			(10	)			(5	)			(9	)			4
Segment Adjusted EBITDA		$	942			$	660			$	282			$	2,967			$	1,796			$	1,171

Gross Margin. For the three and nine months ended September 30, 2013 compared to the same periods last year, gross margin increased $472 million and $1.72 billion, respectively, primarily as a result of ETP’s acquisition of Sunoco, including Sunoco Logistics and retail marketing operations in conjunction with the Holdco Transaction in October 2012. Sunoco Logistics’ gross margin was $241 million and $817 million for the three and nine months ended September 30, 2013, respectively, and retail marketing gross margin was $232 million and $622 million for the three and nine months ended September 30, 2013, respectively. In addition, NGL transportation and services gross margin increased $55 million and $128 million for the three and nine months ended September 30, 2013, respectively, primarily as a result of increased volumes transported and assets recently placed in service. These increases were partially offset by decreases in ETP’s intrastate transportation

 

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and storage gross margin of $26 million and $45 million for the three and nine months ended September 30, 2013, respectively, primarily due to the cessation of certain long-term transportation contracts and a continued unfavorable natural gas price environment.

Unrealized Losses (Gains) on Commodity Risk Management Activities. Unrealized losses (gains) on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory. The increase in unrealized losses on commodity risk management activities for the nine months ended September 30, 2013 compared to 2012 was primarily attributable to natural gas storage inventory and related derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2013 compared to the same periods last year, ETP’s operating expense increases of $36 million and $87 million, respectively, were attributable to Sunoco Logistics, and $103 million and $307 million, respectively, were attributable to ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October of 2012. For the nine months ended September 30, 2013, the increase in operating expenses also reflects a $54 million increase in ETP’s interstate transportation and storage operations primarily due to the consolidation of Southern Union beginning March 26, 2012. In addition, operating expenses increased in ETP’s NGL transportation and midstream operations for the three and nine months ended September 30, 2013 as a result of assets recently being placed in service.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2013 compared to the same periods last year, ETP’s selling, general and administrative increased $29 million and $88 million, respectively, due to the consolidation of Sunoco Logistics, and $25 million and $63 million, respectively, due to the consolidation of ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October of 2012.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the three and nine months ended September 30, 2013 consisted of the following:

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2013				2012				Change				2013				2012				Change
AmeriGas		$	9			$	4			$	5			$	122			$	79			$	43
Citrus			85				81				4				226				162				64
FEP			20				20				—				57				57				—
Regency			26				—				26				42				—				42
Other			11				1				10				27				4				23
Total Adjusted EBITDA related to unconsolidated affiliates		$	151			$	106			$	45			$	474			$	302			$	172

Adjusted EBITDA Related to Discontinued Operations. Amounts reflected the operations of ETC Canyon Pipeline, LLC, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

 

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Investment in Regency

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2013				2012				Change				2013				2012				Change
Revenues		$	665			$	527			$	138			$	1,844			$	1,413			$	431
Cost of products sold			477				369				108				1,309				959				350
Gross margin			188				158				30				535				454				81
Unrealized losses (gains) on commodity risk management activities			9				9				—				2				(7	)			9
Operating expenses, excluding non-cash compensation expense			(76	)			(60	)			(16	)			(215	)			(156	)			(59	)
Selling, general and administrative, excluding non-cash compensation expense			(13	)			(21	)			8				(64	)			(78	)			14
Adjusted EBITDA related to unconsolidated affiliates			65				55				10				188				171				17
Other			(1	)			—				(1	)			—				14				(14	)
Segment Adjusted EBITDA		$	172			$	141			$	31			$	446			$	398			$	48

Gross Margin. Regency’s gross margin increased for the three and nine months ended September 30, 2013 compared to the same periods last year primarily as a result of increased volumes in south and west Texas in Regency’s gathering and processing operations. In addition, because the SUGS Contribution was a transaction between entities under common control, Regency has retrospectively consolidated SUGS beginning March 26, 2012. As such, the nine months ended September 30, 2013 included a full period of SUGS results, while the nine months ended September 30, 2012 included a partial period of SUGS results.

Unrealized Losses (Gains) on Commodity Risk Management Activities. Regency’s gains and losses on commodity risk management activities were primarily due to mark-to-market adjustments on its non-hedged commodity derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses increased for the three and nine months ended September 30, 2013 compared to the same periods last year as a result of organic growth in Regency’s gathering and processing operations. In addition, Regency consolidated SUGS beginning March 26, 2012, which accounted for $41 million of operating expenses as the nine months ended September 30, 2012 included only a partial period of SUGS’ operating expenses.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. Regency’s operating expenses decreased for the three and nine months ended September 30, 2013 compared to the same periods last year primarily as a result of a decrease in employee expenses and a decrease in the management fee paid to ETE. In addition, the nine months ended September 30, 2013 reflected the input of lower allocated overhead related to SUGS.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s adjusted EBITDA related to unconsolidated affiliates increased primarily due to a $23 million increase in adjusted EBITDA attributable to Lone Star as a result of new assets placed in service. The increase was partially offset by an $8 million decrease in Regency’s interest in adjusted EBITDA attributable to HPC.

Other. Regency’s other decreased for the nine months ended September 30, 2013 primarily as the result of recognition of a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts.

 

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Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Consolidated Results

 

		Years Ended December 31,
		2012				2011				Change
Segment Adjusted EBITDA:
Investment in ETP		$	2,744			$	1,781			$	963
Investment in Regency			525				422				103
Corporate and Other			(52	)			(29	)			(23	)
Adjustments and Eliminations(1)			(112	)			(43	)			(69	)
Total			3,105				2,131				974
Depreciation and amortization			(871	)			(586	)			(285	)
Interest expense, net of interest capitalized			(1,018	)			(740	)			(278	)
Bridge loan related fees			(62	)			—				(62	)
Gain on deconsolidation of Propane Business			1,057				—				1,057
Losses on non-hedged interest rate derivatives			(19	)			(78	)			59
Non-cash unit-based compensation expense			(47	)			(42	)			(5	)
Unrealized gains on commodity risk management activities			10				7				3
LIFO valuation reserve			(75	)			—				(75	)
Losses on extinguishments of debt			(123	)			—				(123	)
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes			(435	)			(114	)			(321	)
Adjusted EBITDA related to discontinued operations			(99	)			(23	)			(76	)
Other, net			14				(7	)			21
Income from continuing operations before income tax expense			1,437				548				889
Income tax expense			54				17				37
Income from continuing operations			1,383				531				852
Loss from discontinued operations			(109	)			(3	)			(106	)
Net income		$	1,274			$	528			$	746

 

(1)	See description of eliminations included in Note 18 to our to our audited consolidated financial statements included in this prospectus supplement.

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation and Amortization. Depreciation and amortization increased primarily due to the following:

 

•

depreciation and amortization related to Southern Union of $179 million from March 26, 2012 to December 31, 2012;

 

•

depreciation and amortization related to Sunoco Logistics and Sunoco of $63 million and $32 million, respectively, from October 5, 2012 through December 31, 2012; and

 

•

additional depreciation and amortization recorded from assets placed in service in 2012 and 2011; partially offset by the deconsolidation of ETP’s Propane Business in January 2012, which had recognized depreciation of $4 million and $82 million for years ended December 31, 2012 and 2011.

Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

 

•

interest expense of $130 million recorded by Southern Union from March 26, 2012 through December 31, 2012;

 

•

interest expense of $14 million and $9 million recorded by Sunoco Logistics and Sunoco, respectively, from October 5, 2012 to December 31, 2012;

 

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•

incremental interest expense recorded by ETP primarily due to the issuance of $1.5 billion of senior notes in May 2011 and $2.0 billion of notes in January 2012 to fund acquisitions; and

 

•

an increase of $71 million for the Parent Company primarily related to the Parent Company’s $2.0 billion Senior Secured Term Loan which was used to fund a portion of the cash consideration for the Southern Union Merger; partially offset by a reduction of interest due to ETP’s repurchase of $750 million of its senior notes in January 2012.

Gain on Deconsolidation of Propane Business. ETP recognized a gain on deconsolidation related to the contribution of its Propane Business to AmeriGas in January 2012.

Losses on Non-Hedged Interest Rate Derivatives. Losses on non-hedged interest rate derivatives decreased due to the recognition of losses in 2011 resulting from significant forward rate decreases during 2011.

LIFO Valuation Reserve. A LIFO valuation reserve was recorded for the inventory associated with Sunoco’s retail marketing operations as a result of commodity price changes subsequent to the inventory being recorded at fair value in connection with purchase accounting.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Losses on Extinguishments of Debt. ETP recognized a loss on extinguishment of debt for the year ended December 31, 2012 in connection with its repurchase of approximately $750 million in aggregate principal amount of senior notes in January 2012.

Proportionate Share of Unconsolidated Affiliates’ Interest, Depreciation, Amortization, Non-cash Compensation Expense, Loss on Debt Extinguishment and Taxes. Amounts reflected for 2012 primarily include our proportionate share of such amounts related to AmeriGas, Citrus, FEP, HPC and MEP. The 2011 amounts primarily represented our proportionate share of such amounts and do not include AmeriGas and Citrus.

Adjusted EBITDA Attributable to Discontinued Operations. Amounts reflect the operations of Canyon, which was sold in October 2012, and, for the period from March 26, 2012 to December 31, 2012, Southern Union’s distribution operations.

Other, net. Other, net increased in 2012 primarily due to Southern Union’s recognition of a net curtailment gain of $15 million related to its postretirement benefit plans.

Income Tax Expense. The increase in income tax expense for the year ended December 31, 2012 compared to the same period last year were primarily due to our acquisition of Southern Union in March 2012 which has a higher overall effective rate as Southern Union is subject to federal and state income taxes.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of ETP has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the Sunoco Merger and Holdco Transaction for the year ended December 31, 2012 and 2011, giving effect that each occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Sunoco Merger and Holdco Transaction had been consummated on January 1, 2011.

 

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The following table presents the pro forma financial information for the year ended December 31, 2012:

 

		ETE Historical				Propane Transaction(a)				Sunoco Historical(b)				Southern Union Historical(c)				Holdco Pro Forma Adjustments(d)				Pro Forma
Revenues		$	16,964			$	(93	)		$	35,258			$	443			$	(12,174	)		$	40,398
Costs and expenses:
Cost of products sold—natural gas operations			14,153				(80	)			33,142				302				(11,193	)			36,324
Depreciation and amortization			871				(4	)			168				49				76				1,160
Selling, general and administrative			580				(1	)			459				11				(119	)			930
Impairment charges			—								124								(22	)			102
Total costs and expenses			15,604				(85	)			33,893				362				(11,258	)			38,516
Operating income			1,360				(8	)			1,365				81				(916	)			1,882
Other income (expense):
Interest expense, net of interest capitalized			(1,080	)			(24	)			(123	)			(50	)			2				(1,275	)
Equity in earnings of affiliates			212				19				41				16				5				293
Gain on deconsolidation of Propane Business			1,057				(1,057	)			—				—				—				—
Gain on formation of Philadelphia Energy Solutions			—				—				1,144				—				(1,144	)			—
Loss on extinguishment of debt			(123	)			115				—				—				—				(8	)
Gains (losses) on non-hedged interest rate derivatives			(19	)			—				—				—				—				(19	)
Impairment charges			—				—				—				—				—				—
Other, net			30				2				118				(2	)			(2	)			146
Income from continuing operations before income tax expense (benefit)			1,437				(953	)			2,545				45				(2,055	)			1,019
Income tax expense (benefit)			54				—				956				12				(871	)			151
Income from continuing operations		$	1,383			$	(953	)		$	1,589			$	33			$	(1,184	)		$	868

 

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The following table presents the pro forma financial information for the year ended December 31, 2011:

 

		ETE Historical				Propane Transaction(a)				Sunoco Historical(b)				Southern Union Historical(c)				Holdco Pro Forma Adjustments(d)				Pro Forma
Revenues		$	8,190			$	(1,427	)		$	45,328			$	1,997			$	(16,528	)		$	37,560
Costs and expenses:
Cost of products sold—natural gas operations			6,075				(1,174	)			44,119				1,338				(16,677	)			33,681
Depreciation and amortization			586				(78	)			335				204				(2	)			1,045
Selling, general and administrative			292				(47	)			598				42				(18	)			867
Impairment charges			—				—				2,629				—				(2,569	)			60
Total costs and expenses			6,953				(1,299	)			47,681				1,584				(19,266	)			35,653
Operating income			1,237				(128	)			(2,353	)			413				2,738				1,907
Other income (expense):
Interest expense, net of interest capitalized			(740	)			(40	)			(172	)			(218	)			29				(1,141	)
Equity in earnings of affiliates			117				148				15				99				(158	)			221
Gains (losses) on non-hedged interest rate derivatives			(78	)			—				—				—				—				(78	)
Impairment charges			(5	)			—				—				—				—				(5	)
Other, net			17				2				44				—				(2	)			61
Income from continuing operations before income tax expense (benefit)			548				(18	)			(2,466	)			294				2,607				965
Income tax expense (benefit)			17				(4	)			(1,063	)			80				1,070				100
Income from continuing operations		$	531			$	(14	)		$	(1,403	)		$	214			$	1,537			$	865

 

(a)	Propane Transaction adjustments reflect the following:

 

•

The adjustments reflect the deconsolidation of ETP’s propane operations in connection with the Propane Transaction.

 

•

The adjustments reflect the pro forma impacts from the consideration received in connection with the Propane Transaction, including ETP’s receipt of AmeriGas common units and ETP’s use of cash proceeds from the transaction to redeem long-term debt.

 

•

The 2012 adjustments include the elimination of (i) the gain recognized by ETP in connection with the deconsolidation of the Propane Business and (ii) ETP’s loss on extinguishment of debt recognized in connection with the use of proceeds to redeem of long-term debt.

 

(b)	Sunoco historical amounts in 2012 include only the period from January 1, 2012 through September 30, 2012.

(c)	Southern Union historical amounts in 2012 include only the period from January 1, 2012 through March 25, 2012.

(d)	Substantially all of the Holdco pro forma adjustments relate to Sunoco’s exit from its Northeast refining operations and formation of the PES joint venture, except for the following:

 

•

The adjustment to depreciation and amortization reflects incremental amounts for estimated fair values recorded in purchase accounting related to Sunoco and Southern Union.

 

•

The adjustment to selling, general and administrative expenses includes the elimination of merger-related costs incurred, because such costs would not have a continuing impact on results of operations.

 

•

The adjustment to interest expense includes incremental amortization of fair value adjustments to debt recorded in purchase accounting.

 

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•

The adjustment to equity in earnings of affiliates reflects the reversal of amounts related to Citrus recorded in Southern Union’s historical income statements.

 

•

The adjustment to income tax expense includes the pro forma impact resulting from the pro forma adjustments to pre-tax income of Sunoco and Southern Union.

Segment Operating Results

Investment in ETP

 

		Years Ended December 31,
		2012				2011				Change
Revenues		$	15,702			$	6,799			$	8,903
Cost of products sold			12,266				4,175				8,091
Gross margin			3,436				2,624				812
Unrealized losses on commodity risk management activities			9				11				(2	)
Operating expenses, excluding non-cash compensation expense			(899	)			(761	)			(138	)
Selling, general and administrative, excluding non-cash compensation expense			(457	)			(174	)			(283	)
LIFO valuation adjustments			75				—				75
Adjusted EBITDA related to unconsolidated affiliates			480				56				424
Adjusted EBITDA related to discontinued operations			99				23				76
Other			1				2				(1	)
Segment Adjusted EBITDA		$	2,744			$	1,781			$	963

Gross Margin. ETP’s gross margin increased primarily as a result of the following:

 

•

An increase in revenues from ETP’s interstate transportation and storage operations, primarily as a result of increased volume due to the consolidation of Southern Union’s transportation and storage businesses beginning March 26, 2012, accounted for $662 million of the increase on ETP’s gross margin;

 

•

ETP’s gross margin increased as a result of ETP’s acquisition of Sunoco, including Sunoco Logistics and retail marketing operations, in conjunction with the Holdco Transaction in October 2012. Sunoco Logistics’ gross margin was $351 million and retail marketing’s gross margin was $169 million from ETP’s acquisition to December 31, 2012;

 

•

Midstream operations’ gross margin increased $181 million primarily due to $125 million of incremental non-fee based revenues from the consolidation of Southern Union’s gathering and process businesses beginning March 26, 2013. In addition, increased inlet volumes as a result of more production by customers in the Eagle Ford Shale area and increased capacity from recently completed projects; and

 

•

NGL transportation and services operations’ gross margin increased $110 million primarily as a result of a full year of activity in 2012 compared to eight months of activity in 2011, in addition to the impact from assets being placed in service in 2012; offset by

 

•

Lower margin from ETP’s intrastate transportation and storage operations due to:

 

•

A decrease of $49 million in transportation fees due to unfavorable market conditions and the cessation of certain long-term transportation contracts; and

 

•

A decrease of $51 million in retained fuel revenues due to less retained volumes and a decline in the average of natural gas spot prices; further offset by

 

•

ETP’s contribution of its retail propane operations in January 2012.

Unrealized Losses on Commodity Risk Management Activities. Unrealized losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory.

 

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Operating Expenses, Excluding Non-Cash Compensation Expense. ETP’s operating expense increase of $95 million was attributable to Sunoco Logistics and $119 million was attributable to ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October of 2012. Additionally, the increase in operating expenses reflected a $151 million increase in ETP’s interstate transportation and storage operations and $68 million in ETP’s midstream operations primarily due to the consolidation of Southern Union beginning March 26, 2012. These increases were offset by the impact of ETP’s deconsolidation of its retail propane operations in January 2012.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. The increase in selling, general and administrative expenses was primarily due to ETP’s consolidation of Southern Union beginning March 26, 2012. Additionally, selling, general and administrative expenses of $32 million were attributable to Sunoco Logistics and $17 million were attributable to ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October 2012.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates consisted of the following:

 

		Years Ended December  31,
		2012				2011				Change
AmeriGas		$	139			$	—			$	139
Citrus			228				—				228
FEP			77				53				24
Other			36				3				33
Total Adjusted EBITDA related to unconsolidated affiliates		$	480			$	56			$	424

Adjusted EBITDA Related to Discontinued Operations. Amounts reflected the operations of Canyon, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

Investment in Regency

 

		Years Ended December  31,
		2012				2011				Change
Revenues		$	2,000			$	1,434			$	566
Cost of products sold			1,387				1,013				374
Gross margin			613				421				192
Unrealized gains on commodity risk management activities			(5	)			—				(5	)
Operating expenses, excluding non-cash compensation expense			(223	)			(144	)			(79	)
Selling, general and administrative expense			(100	)			(67	)			(33	)
Adjusted EBITDA related to unconsolidated affiliates			227				213				14
Other			13				(1	)			14
Segment Adjusted EBITDA		$	525			$	422			$	103

Gross Margin. Regency’s gross margin increased due to:

 

•

$144 million of gross margin recognized by SUGS from March 26, 2012 through December 31, 2012; and

 

•

$41 million primarily due to increased volumes in Regency’s South and West Texas and North Louisiana gathering and processing operations.

 

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Unrealized Gains on Commodity Risk Management Activities. Regency’s gains on commodity risk management activities increased primarily due to mark-to-market adjustments on its non-hedged commodity derivatives during the year ended December 31, 2012.

Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses, excluding non-cash compensation expenses, increased primarily due to $62 million recognized by SUGS from March 26, 2012 through December 31, 2012. Additionally, operating expenses increased due to increased pipeline and plant operating activity in South and West Texas, increased compressor maintenance expense primarily due to increases in maintenance and materials costs, and increases in ad valorem taxes related to organic growth projects.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. Regency’s selling, general and administrative expenses, increased primarily due to $37 million recognized by SUGS from March 26, 2012 through December 31, 2012. This increase was partially offset by a decrease of approximately $5 million as a result of lower professional fees and lower rent expense.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s adjusted EBITDA attributable to unconsolidated affiliates increased $14 million primarily due to the impact from Lone Star, which was formed in May 2011.

Other. Regency’s other increased primarily as the result of recognition of a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts.

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

Consolidated Results

 

		Years Ended December  31,
		2011				2010				Change
Segment Adjusted EBITDA:
Investment in ETP		$	1,781			$	1,541			$	240
Investment in Regency			422				218				204
Corporate and Other			(29	)			(21	)			(8	)
Adjustments and Eliminations(1)			(43	)			—				(43	)
Total			2,131				1,738				393
Depreciation and amortization			(586	)			(406	)			(180	)
Interest expense, net of interest capitalized			(740	)			(625	)			(115	)
Losses on non-hedged interest rate derivatives			(78	)			(52	)			(26	)
Non-cash unit-based compensation expense			(42	)			(31	)			(11	)
Unrealized gains (losses) on commodity risk management activities			7				(110	)			117
Losses on extinguishments of debt			—				(16	)			16
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes			(114	)			(71	)			(43	)
Adjusted EBITDA related to discontinued operations			(23	)			(19	)			(4	)
Other, net			(7	)			(49	)			42
Income from continuing operations before income tax expense			548				359				189
Income tax expense			17				14				3
Income from continuing operations			531				345				186
Loss from discontinued operations			(3	)			(8	)			5
Net income		$	528			$	337			$	191

 

(1)	See description of eliminations included in Note 18 to our audited consolidated financial statements included in this prospectus supplement.

 

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See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation and Amortization. Depreciation and amortization increased due to acquisitions and assets placed in service since 2010. Depreciation and amortization increased by $28 million for ETP’s interstate transportation operations primarily due to the Tiger pipeline which was placed in service in December 2010. Depreciation and amortization increased by $25 million for ETP’s midstream operations primarily due to incremental depreciation from the continued expansion of its Northern Louisiana and Southeast Texas assets. Depreciation and amortization for ETP’s NGL transportation and services operations was $33 million from its inception in May 2011 through December 31, 2011.

In addition, depreciation and amortization increased in 2011 as a result of the consolidation of Regency beginning May 26, 2010.

Interest Expense, Net of Interest Capitalized. For the year ended December 31, 2011 compared to the year ended December 31, 2010, interest expense increased primarily due to the following:

 

•

ETP’s issuance of $1.5 billion of senior notes in May 2011, the proceeds from which were used to repay borrowings on its revolving credit facility, to fund growth projects and for general partnership purposes;

 

•

As a result of the consolidation of Regency beginning May 26, 2010; and

 

•

Distributions on the Preferred Units issued by ETE in connection with the acquisition of a controlling interest in Regency in May 2010. Distributions on the Preferred Units were $24 million and $14 million for the years ended December 31, 2011 and 2010, respectively.

The above mentioned increases in interest were partially offset by a decrease in interest expense at the Parent Company primarily due to the recognition of $66 million of realized losses on hedged interest rate swaps in September 2010 in connection with the refinancing of indebtedness that would have come due in 2011 and 2012. These realized losses were offset by an increase in interest expense that primarily resulted from the Parent Company’s issuance of $1.8 billion of aggregate principal amount of 7.5% senior notes in September 2010.

Losses on Non-Hedged Interest Rate Derivatives. In September 2010, the Parent Company terminated its interest swaps that were not accounted for as hedges in connection with its issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings.

The year ended December 31, 2011 reflected losses on non-hedged interest rate swaps for which ETP had total notional amounts outstanding of $1.65 billion as of December 31, 2011, which included $1.15 billion of forward-starting floating-to-fixed swaps used to hedge interest rates associated with anticipated note issuances and $500 million of fixed-to-floating swaps used to swap a portion of ETP’s fixed rate debt to floating. During the second half of 2011, forward rates decreased significantly due to global economic uncertainty which resulted in unrealized non-cash losses on ETP’s forward-starting floating-to-fixed swaps.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of the unrealized loss on commodity risk management activities included in the discussion of segment results below.

Proportionate Share of Unconsolidated Affiliates’ Interest, Depreciation, Amortization, Non-cash Compensation Expense, Loss on Debt Extinguishment and Taxes. Amounts reflected for 2011 primarily include our proportionate share of such amounts related to FEP, HPC and MEP. The 2010 amounts primarily represented our proportionate share of such amounts and do not include HPC prior to our acquisition of control of Regency in May 2010.

Income Tax Expense. The increase in income tax expense between the periods was primarily due to increases in taxable income within ETP’s subsidiaries that are taxable corporations, in addition to an increase in amounts recorded for the Texas margins tax resulting from increased operating income.

 

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Segment Operating Results

Investment in ETP

 

		Years Ended December 31,
		2011				2010				Change
Revenues		$	6,799			$	5,843			$	956
Cost of products sold			4,175				3,591				584
Gross margin			2,624				2,252				372
Unrealized losses on commodity risk management activities			11				78				(67	)
Operating expenses, excluding non-cash compensation expense			(761	)			(695	)			(66	)
Selling, general and administrative, excluding non-cash compensation expense			(174	)			(149	)			(25	)
Adjusted EBITDA related to unconsolidated affiliates			56				35				21
Adjusted EBITDA related to discontinued operations			23				19				4
Other			2				1				1
Segment Adjusted EBITDA		$	1,781			$	1,541			$	240

Gross Margin. For the year ended December 31, 2011 compared to the year ended December 31, 2010, ETP’s gross margin increased primarily due to the net impacts of the following:

 

•

Revenue generated by ETP’s interstate transportation operations increased $154 million primarily as a result of incremental revenues from the Tiger pipeline being placed into service in December 2010 and a related expansion placed into service in August 2011. Increased revenue from the Tiger pipeline was partially offset by decreased revenue from the Transwestern pipeline as a result of lower volumes.

 

•

Gross margin from ETP’s midstream operations increased $93 million, $55 million of which was a result from increases in gathering and processing fee-based revenues primarily due to increased volumes in production in the Eagle Ford Shale along with increased volumes in ETP’s assets in West Virginia and North Texas. Gross margin for non fee-based contracts and processing increased $49 million primarily due to more favorable NGL prices.

 

•

Gross margin from ETP’s NGL transportation and services operations was $179 million during 2011, which represented 100% of the results from Lone Star since LDH Energy Asset Holdings LLC (“LDH”) was acquired in May 2011. Accordingly, no comparative amounts were reflected in ETP’s results prior to May 2, 2011.

 

•

Gross margin from ETP’s retail propane and other retail propane related operations decreased $37 million primarily as a result of decreased volumes which were affected by unfavorable weather patterns and continued customer conservatism.

Unrealized Losses on Commodity Risk Management Activities. Unrealized losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory. Unrealized losses related to intrastate transportation and storage operations decreased $53 million, primarily due to the timing of storage withdrawals and declining forward prices, in addition to mark-to-market losses of $8 million in 2011 not related to storage. ETP’s midstream operations recorded unrealized gains of $3 million in 2011 compared to unrealized losses of $13 million in 2010 primarily due to a decrease in the volume of hedging activities of its marketing affiliate.

Operating Expenses, Excluding Non-Cash Compensation Expense. Operating expenses increased during 2011 compared to 2010 primarily due to operating expenses of $39 million for Lone Star, which acquired LDH in May 2011 and was not reflected in the prior period. In addition, operating expenses for ETP’s midstream operations increased $17 million as a result of increased maintenance and operating expenses and employee

 

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expenses due to higher volumes and assets on its systems and processing/treating facilities. The completion of the Tiger pipeline and its related expansion also attributed to increases in operating expenses.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. Selling, general and administrative expenses increased partially due to selling, general and administrative expenses of $13 million for Lone Star, which was acquired in May 2011 and not reflected in the prior period. In addition, selling, general and administrative expenses for ETP’s interstate operations increased $14 million primarily due to increased allocated and employee-related expenses, including incremental amounts related to the Tiger pipeline.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates consisted of the following:

 

		Years Ended December 31,
		2011				2010				Change
FEP		$	53			$	—			$	53
MEP			—				32				(32	)
Other			3				3				—
Total Adjusted EBITDA related to unconsolidated affiliates		$	56			$	35			$	21

Adjusted EBITDA Related to Discontinued Operations. Amounts reflected the operations of Canyon, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

Investment in Regency

 

		Years Ended December 31,
		2011				2010				Change
Revenues		$	1,434			$	716			$	718
Cost of products sold			1,013				504				509
Gross margin			421				212				209
Unrealized losses on commodity risk management activities			—				23				(23	)
Operating expenses, excluding non-cash compensation expense			(144	)			(76	)			(68	)
Selling, general and administrative			(67	)			(44	)			(23	)
Adjusted EBITDA related to unconsolidated affiliates			213				102				111
Other			(1	)			1				(2	)
Segment Adjusted EBITDA		$	422			$	218			$	204

ETE obtained control of Regency on May 26, 2010. Changes between the year ended December 31, 2011 and the period from May 26, 2010 to December 31, 2010 were primarily due to the consolidation of Regency beginning May 26, 2010.

Liquidity and Capital Resources

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The amount of cash that ETP and Regency distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their

 

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respective business activities and the amount of available cash, as discussed below. ETP and Regency’s ability to make distributions to us is limited by restrictions contained in their respective debt agreements. In connection with previous transactions, we have relinquished a portion of incentive distributions to be received from ETP and Regency.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP and Regency. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholders on a quarterly basis.

We expect ETP and Regency to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

ETP

ETP’s ability to satisfy its obligations and pay distributions to its unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of ETP’s management.

ETP currently expects capital expenditures for the full year 2013 to be within the following ranges:

 

		Growth								Maintenance
		Low				High				Low				High
Intrastate transportation and storage		$	5			$	5			$	25			$	30
Interstate transportation and storage			40				50				75				90
Midstream(1)			455				475				40				45
NGL transportation and services(2)			420				425				15				20
Investment in Sunoco Logistics			880				920				60				65
Retail marketing			65				75				65				75
All other (including eliminations)			20				25				40				45
Total projected capital expenditures		$	1,885			$	1,975			$	320			$	370

 

(1)	Amounts reflected above for the midstream segment include growth and maintenance capital expenditures of $95 million and $10 million, respectively, incurred by Southern Union’s gathering and processing operations prior to deconsolidation on April 30, 2013.

(2)	ETP expects to receive $120 million in capital contributions from Regency related to Regency’s 30% share of Lone Star.

Sunoco Logistics expects total growth capital expenditures of approximately $1.3 billion in 2014, and ETP expects to publicly announce expected 2014 capital expenditures for its other operations prior to the filing of its Annual Report on Form 10-K for the year ended December 31, 2013.

The assets used in ETP’s natural gas operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. From time to time, ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe in a timely manner, higher steel prices and other factors beyond ETP’s control. However, ETP includes these factors in its anticipated growth capital expenditures for each year.

 

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ETP generally funds its capital requirements with cash flows from operating activities, borrowings under its revolving credit facility, the issuance of long-term debt or common units or a combination thereof. Based on ETP’s current estimates, it expects to utilize capacity under the revolving credit facility, along with cash from operations, to fund its announced growth capital expenditures and working capital needs through the end of 2013; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

Regency

Regency expects its sources of liquidity to include: cash generated from operations and occasional asset sales; borrowings under its revolving credit facility; distributions received from unconsolidated affiliates; debt offerings; and issuance of additional partnership units.

In 2013, Regency expects to invest $870 million in growth capital expenditures, of which $500 million is expected to be invested in organic growth projects in the gathering and processing operations; $150 million is expected to be invested in Regency’s portion of growth capital expenditures in its NGL services segment; and $220 million is expected to be invested in growth capital expenditures in its contract services segment. In addition, Regency expects to invest $40 million in maintenance capital expenditures in 2013, including its proportionate share related to joint ventures.

Regency has not publicly announced its expected capital expenditures for 2014.

Regency may revise the timing of these expenditures as necessary to adapt to economic conditions. Regency expects to fund its growth capital expenditures with borrowings under its revolving credit facility and a combination of debt and equity issuances.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our operating entities products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of acquisitions and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and non-cash compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from the construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Nine months ended September 30, 2013. Cash provided by operating activities during 2013 was $1.85 billion. Net income was $1.02 billion for 2013. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $944 million and changes in operating assets

 

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and liabilities of $382 million for 2013. The non-cash activity in 2013 consisted primarily of depreciation and amortization of $962 million. Cash paid for interest, net of interest capitalized, was $944 million for the nine months ended September 30. Capitalized interest for the nine months ended September 30, 2013 was $32 million.

Year ended December 31, 2012. Cash provided by operating activities in 2012 was $1.08 billion and net income was $1.27 billion. The difference between net income and cash provided by operating activities in 2012 consisted of net non-cash items totaling $85 million and changes in operating assets and liabilities of $551 million. The non-cash activity consisted primarily of a gain on the deconsolidation of ETP’s propane business of $1.06 billion, which was offset by depreciation and amortization of $871 million, losses on extinguishments of debt of $123 million and non-cash compensation expense of $47 million.

Year ended December 31, 2011. Cash provided by operating activities in 2011 was $1.38 billion and net income was $528 million. The difference between net income and cash provided by operating activities in 2011 consisted of non-cash items totaling $687 million and changes in operating assets and liabilities of $158 million. The difference between net income and the net cash provided by operating activities also included distributions received from affiliates that exceeded equity in earnings by $3 million. The non-cash activity consisted primarily of depreciation and amortization of $612 million and non-cash compensation expense of $42 million.

Year ended December 31, 2010. Cash provided by operating activities in 2010 was $1.09 billion and net income was $337 million. The difference between net income and cash provided by operating activities in 2010 consisted of non-cash items totaling $553 million and changes in operating assets and liabilities of $260 million. The difference between net income and the net cash provided by operating activities also included ETP interest rate swap termination proceeds of $26 million, ETE payments to terminate interest rate swaps of $169 million and distributions received from our affiliates that exceeded our equity in earnings by $80 million. The non-cash activity consisted primarily of depreciation and amortization of $431 million and an impairment in ETP’s investment of an affiliate of $53 million. In addition, non-cash compensation expense was $31 million. These amounts are partially offset by the allowance for equity funds used during construction of $29 million.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in growth capital expenditures to fund construction and expansion projects.

Nine months ended September 30, 2013 Cash used in investing activities during 2013 was $833 million. In 2013, we received $973 million and $346 million in cash from the sale of the Missouri Gas Energy assets and the sale of AmeriGas common units, respectively. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2013 were $2.50 billion, including changes in accruals of $111 million.

Year ended December 31, 2012. Cash used in investing activities in 2012 of $4.20 billion was comprised primarily of capital expenditures of $3.27 billion (excluding the allowance for equity funds used during construction). ETP invested $2.70 billion for growth capital expenditures and $143 million for maintenance capital expenditures during 2012. Regency invested $767 million for growth capital expenditures and $34 million for maintenance capital during 2012. Cash paid for the acquisition of Southern Union was $2.97 billion and ETP received $1.44 billion in proceeds from the Propane Transaction.

Year ended December 31, 2011. Cash used in investing activities in 2011 of $3.87 billion was comprised primarily of capital expenditures of $1.81 billion (excluding the allowance for equity funds used during construction). ETP invested $1.42 billion for growth capital expenditures and $134 million for maintenance capital expenditures during 2011. Regency invested $354 million for growth capital expenditures and $22 million for maintenance capital during 2011. In addition, our subsidiaries paid cash for acquisitions of $1.97 billion, which primarily consisted of the acquisition of Lone Star and made net advances to joint ventures of $150 million.

 

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Year ended December 31, 2010. Cash used in investing activities in 2010 of $1.83 billion was comprised primarily of total capital expenditures of $1.51 billion (excluding the allowance for equity funds used during construction). ETP invested $1.29 billion for growth capital expenditures in 2010 (primarily related to the Tiger pipeline) and $99 million for maintenance capital expenditures. Regency invested $152 million for growth capital expenditures and $7 million for maintenance capital expenditures between May 26, 2010 and December 31, 2010. In addition, Regency paid cash for acquisitions of $191 million, ETP paid cash for acquisitions of $178 million, and we received $24 million in cash from the acquisition of Regency. Regency received $70 million in cash for the sale of its East Texas assets. Our subsidiaries made advances to joint ventures of $93 million.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund acquisitions and growth capital expenditures. Distribution increases between the periods based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries and increases in the number of our common units outstanding.

Nine months ended September 30, 2013. Cash used in financing activities during 2013 was $209 million. In 2013, ETP received $1.30 billion in net proceeds from offerings of its common units. In 2013, Regency received $149 million in net proceeds from offerings of its common. During 2013, we had a consolidated net increase in our debt level of $329 million. We paid distributions of $544 million to our partners in 2013. Our subsidiaries paid distributions to noncontrolling interest of $1.050 billion in 2013. In 2013, we also paid $340 million to redeem our Series A Convertible Preferred Units (the “Preferred Units”).

Year ended December 31, 2012. Cash provided by financing activities was $3.36 billion in 2012. We had a consolidated increase in our debt level of $4.02 billion, which primarily consisted of borrowings to fund our acquisitions of Southern Union and Sunoco. Our subsidiaries also received $1.10 billion in proceeds from common unit offerings, which consisted of $791 million from the issuance of ETP common units and $312 million from the issuance of Regency common units. We paid distributions to partners of $666 million and $24 million to the holders of our Preferred Units. In addition, our subsidiaries paid $1.02 billion on limited partner interests other than those held by the Parent Company.

Year ended December 31, 2011. Cash provided by financing activities was $2.54 billion in 2011. ETP received $1.47 billion in net proceeds from offerings of ETP common units, including $96 million under its equity distribution program (see Note 8 to our audited consolidated financial statements included in this prospectus supplement). In addition, Regency received $436 million in net proceeds from offerings of Regency common units. We had a consolidated net increase in our debt level of $2.00 billion and paid distributions of $526 million to our common unitholders and $24 million to the holders of our Preferred Units. In addition, ETP paid distributions of $562 million on limited partner interests other than those held by the Parent Company and Regency paid $217 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

Year ended December 31, 2010. Cash provided by financing activities was $761 million in 2010. ETP received $1.15 billion in net proceeds from offerings of ETP common units, including $239 million under ETP’s equity distribution program. In addition, Regency received $400 million in net proceeds from offerings of Regency common units. We had a consolidated net increase in our debt level of $310 million and paid distributions of $483 million to our common unitholders and $14 million to our preferred unitholders. In addition, ETP paid distributions of $476 million on limited partner interests other than those held by the Parent Company, and Regency paid $92 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

 

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Financing activities in 2010 also include the Parent Company’s completion of $1.8 billion of senior notes in September 2010, the proceeds of which were used to repay outstanding indebtedness under existing credit facilities.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

 

		September 30, 2013				December 31, 2012
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020		$	1,800			$	1,800
ETE Senior Secured Term Loan, due March 26, 2017			900				2,000
ETE Senior Secured Revolving Credit Facility			—				60
Subsidiary Indebtedness:
ETP			11,182				7,692
Transwestern			870				870
Regency			2,800				1,962
Southern Union			170				1,260
Panhandle			916				1,621
Sunoco			965				965
Sunoco Logistics			2,150				1,450
Revolving Credit Facilities			211				1,936
Other Long-Term Debt			46				48
Unamortized premiums and fair value adjustments, net			299				389
Total			22,309				22,053
Current maturities			(298	)			(613	)
Long-term debt and notes payable, less current maturities		$	22,011			$	21,440

The terms of our consolidated indebtedness are described in more detail in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 1, 2013, in Note 8 to our unaudited consolidated financial statements included in this prospectus supplement and the section entitled “Description of Other Indebtedness” elsewhere in this prospectus supplement.

Parent Company Tender Offer

On October 30, 2013, the Parent Company commenced an offer to purchase for cash up to $400 million aggregate principal amount outstanding of its 2020 Notes pursuant to the Offer to Purchase Statement dated October 30, 2013. Please read “Prospectus Supplement Summary—Refinancing Transactions—Tender Offer” for more information.

Senior Notes Offerings

In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 1, 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 1, 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 1, 2043. ETP used the net proceeds of approximately $1.47 billion from the offerings to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes.

In addition, in September 2013, Regency issued $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020. Regency used the net proceeds of approximately $394 million to repay borrowings outstanding under its revolving credit facility.

 

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Revolving Credit Facilities

Parent Company Credit Facility

The Parent Company has a $200 million revolving credit facility that expires in September 2015. Indebtedness under the Parent Company revolving credit facility is secured by all of its and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

As of September 30, 2013, we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility, which expires in October 2016. Indebtedness under the revolving credit facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. There were no outstanding borrowings under the revolving credit facility as of September 30, 2013.

Regency Credit Facility

Regency has a $1.2 billion revolving credit facility with a $300 million uncommitted incremental facility that matures on May 21, 2018. Indebtedness under Regency’s revolving credit facility is secured by all of Regency’s and certain of its subsidiaries’ tangible and intangible assets and guaranteed by certain of Regency’s subsidiaries.

As of September 30, 2013, there was a balance outstanding under Regency’s revolving credit facility of $176 million in revolving credit loans and approximately $15 million in letters of credit. The total amount available under Regency’s revolving credit facility, as of September 30, 2013, which was reduced by any letters of credit, was approximately $1.01 billion, and the weighted average interest rate on the total amount outstanding as of September 30, 2013 was 2.19%.

Southern Union Credit Facilities

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under Southern Union’s credit facility and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2014. There were no outstanding borrowings under these facilities as of September 30, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility which expires in April 2015. Outstanding borrowings under this credit facility were $35 million as of September 30, 2013.

Covenants Related to Our Credit Agreements

We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our respective credit agreements as of September 30, 2013. See “Description of Other Indebtedness.”

 

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Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company’s partnership agreement, the Parent Company will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any 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 our general partner that is necessary or appropriate to provide for future cash requirements.

Following are distributions declared and/or paid by us subsequent to December 31, 2009:

 

Quarter Ended		Record Date		Payment Date		Rate
September 30, 2013		November 4, 2013		November 19, 2013		$0.6725
June 30, 2013		August 5, 2013		August 19, 2013		0.6550
March 31, 2013		May 6, 2013		May 17, 2013		0.6450
December 31, 2012		February 7, 2013		February 19, 2013		0.6350
September 30, 2012		November 6, 2012		November 16, 2012		$0.6250
June 30, 2012		August 6, 2012		August 17, 2012		0.6250
March 31, 2012		May 4, 2012		May 18, 2012		0.6250
December 31, 2011		February 7, 2012		February 17, 2012		0.6250
September 30, 2011		November 4, 2011		November 18, 2011		$0.6250
June 30, 2011		August 5, 2011		August 19, 2011		0.6250
March 31, 2011		May 6, 2011		May 19, 2011		0.5600
December 31, 2010		February 7, 2011		February 18, 2011		0.5400
September 30, 2010		November 8, 2010		November 19, 2010		$0.5400
June 30, 2010		August 9, 2010		August 19, 2010		0.5400
March 31, 2010		May 7, 2010		May 19, 2010		0.5400
December 31, 2009		February 8, 2010		February 19, 2010		0.5400

The total amounts of distributions declared and/or paid during the nine months ended September 30, 2013 and 2012 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):

 

		Nine Months Ended September 30,								Year Ended December 31,
		2013				2012				2012				2011				2010
Limited Partners		$	554			$	525			$	703			$	543			$	482
General Partner interest			1				1				1				2				1
Total Parent Company distributions		$	555			$	526			$	704			$	545			$	483

 

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Cash Distributions Received from Subsidiaries

The Parent Company’s principal sources of cash flow includes the distributions that it receives from its direct and indirect investments in ETP and Regency. ETP and Regency’s ability to make distributions are limited by restrictions contained in their respective debt agreements. The total amount of distributions the Parent Company received or will receive from ETP and Regency relating to our limited partner interests, general partner interest and incentive distribution rights (shown in the period to which they relate) for the periods ended as noted below is as follows:

 

		Nine Months Ended September 30,								Years Ended December 31,
		2013				2012				2012				2011				2010
Distributions from ETP:
Limited Partners(1)		$	223			$	135			$	180			$	180			$	191
Class H Units held by ETE Holdings			16				—				—				—				—
General Partner interest			15				15				20				20				20
IDRs(2)			421				322				439				422				376
Total distributions from ETP(3)			675				472				639				622				587
Distributions from Regency:
Limited Partners			36				36				48				48				35
General Partner interest			3				4				5				5				4
IDRs(4)			6				6				8				6				3
Total distributions from Regency			45				46				61				59				42
Total distributions received from subsidiaries		$	720			$	518			$	700			$	681			$	629

 

(1)	Does not include common unit distributions received by Southern Union in respect of approximately 2,249,092 ETP common units issued to Southern Union in connection with the Citrus Merger.

(2)	Amounts are net of the following incentive distributions ETE has agreed to relinquish to ETP:

 

•

In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of the incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

 

•

In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

 

•

As discussed in Note 2 to our unaudited consolidated financial statements included in this prospectus supplement, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued common units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

 

•

As discussed in Note 10 to our unaudited consolidated financial statements included in this prospectus supplement, ETP has agreed to make incremental cash distributions in the aggregate amount of $329 million to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

 

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As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

 

		Quarters Ending
		March 31				June 30				September 30				December 31				Total Year
2013			N/A				N/A			$	21.00			$	21.00			$	42.00
2014		$	27.25			$	27.25				27.25				27.25				109.00
2015			13.25				13.25				13.25				13.25				53.00
2016			5.50				5.50				5.50				5.50				22.00

 

(3)	Total distributions received from ETP does not include distributions on ETP’s Class E Units or Class F Units, which are held by subsidiaries of ETP Holdco, which was 60% owned by ETE subsequent to October 5, 2012, and 100% owned by ETP subsequent to April 30, 2013.

(4)	In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

Cash Distributions Paid by Subsidiaries

ETP and Regency are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

Cash Distributions Paid by ETP

Following are distributions declared and/or paid by ETP subsequent to December 31, 2009:

 

Quarter Ended		Record Date		Payment Date		Rate
September 30, 2013		November 4, 2013		February 14, 2013		$	0.90500
June 30, 2013		August 5, 2013		May 15, 2013			0.89375
March, 31, 2013		May 6, 2013		August 14, 2013			0.89375
December 31, 2012		February 7, 2013		November 14, 2013			0.89375
September 30, 2012		November 6, 2012		November 14, 2012		$	0.89375
June 30, 2012		August 6, 2012		August 14, 2012			0.89375
March 31, 2012		May 4, 2012		May 15, 2012			0.89375
December 31, 2011		February 7, 2012		February 14, 2012			0.89375
September 30, 2011		November 4, 2011		November 14, 2011		$	0.89375
June 30, 2011		August 5, 2011		August 15, 2011			0.89375
March 31, 2011		May 6, 2011		May 16, 2011			0.89375
December 31, 2010		February 7, 2011		February 14, 2011			0.89375
September 30, 2010		November 8, 2010		November 15, 2010		$	0.89375
June 30, 2010		August 9, 2010		August 16, 2010			0.89375
March 31, 2010		May 7, 2010		May 17, 2010			0.89375
December 31, 2009		February 8, 2010		February 15, 2010			0.89375

 

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The total amounts of ETP distributions declared during the nine months ended September 30, 2013 and 2012 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2013				2012				2012				2011				2010
Limited Partners		$	979			$	694			$	963			$	762			$	677
General Partner interest			15				15				20				20				20
IDRs			421				322				439				422				376
Total ETP distributions		$	1,415			$	1,031			$	1,422			$	1,204			$	1,073

The distributions reflected above for the nine months ended September 30, 2013 reflect IDR reductions totaling $107 million, which includes three quarters of IDR relinquishment related to the Citrus Merger, three quarters of IDR relinquishment related to the Holdco Transaction and two quarters of IDR relinquishment related to the Holdco Acquisition. The distributions reflected above for the nine months ended September 30, 2012 reflect IDR reductions totaling $59 million, which includes three quarters of IDR relinquishment related to the Citrus Merger and one quarter of IDR relinquishment related to the Holdco Transaction.

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to ETE’s acquisition of Regency’s general partner in May 2010:

 

Quarter Ended		Record Date		Payment Date		Rate
September 30, 2013		November 4, 2013		November 14, 2013		$	0.470
June 30, 2013		August 5, 2013		August 14, 2013			0.465
March 31, 2013		May 6, 2013		May 13, 2013			0.460
December 31, 2012		February 7, 2013		February 14, 2012			0.460
September 30, 2012		November 6, 2012		November 14, 2012		$	0.460
June 30, 2012		August 6, 2012		August 12, 2012			0.460
March 31, 2012		May 7, 2012		May 14, 2012			0.460
December 31, 2011		February 6, 2012		February 13, 2012			0.460
September 30, 2011		November 7, 2011		November 14, 2011		$	0.455
June 30, 2011		August 6, 2011		August 12, 2011			0.450
March 31, 2011		May 6, 2011		May 13, 2011			0.445
December 31, 2010		February 7, 2011		February 14, 2011			0.445
September 30, 2010		November 5, 2010		November 12, 2010		$	0.445
June 30, 2010		August 6, 2010		August 13, 2010			0.445

 

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The total amounts of Regency distributions declared and/or paid during the nine months ended September 30, 2013 and 2012 (subsequent to ETE’s acquisition of Regency’s general partner in May 2010) were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

 

		Nine Months Ended September 30,								Years Ended December 31,
		2013				2012				2012				2011				2010
Limited Partners		$	289			$	235			$	314			$	275			$	175
General Partner interest			3				4				5				5				4
IDRs			6				6				8				6				3
Total Regency distributions		$	298			$	245			$	327			$	286			$	182

Cash Distributions Paid by Sunoco Logistics

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

 

Quarter Ended		Record Date		Payment Date		Rate
September 30, 2013		November 8, 2013		November 14, 2013		$	0.6300
June 30, 2013		August 8, 2013		August 14, 2013			0.6000
March 31, 2013		May 9, 2013		May 15, 2013			0.5725
December 31, 2012		February 8, 2013		February 14, 2013			0.5450

The total amounts of Sunoco Logistics distributions declared and/or paid during the nine months ended September 30, 2013 were as follows (all from Sunoco Logistics’ operating surplus and are shown in the period with respect to which they relate):

 

		Nine Months  Ended September 30, 2013
Limited Partners:
Common Units		$	186
General Partner interest			3
IDRs			84
Total Sunoco Logistics distributions		$	273

Sunoco Logistics declared $147 million in cash distributions to ETP for the nine months ended September 30, 2013.

Critical Accounting Policies

Disclosure of our critical accounting policies is included in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 1, 2013 and incorporated by reference in this prospectus supplement.

 

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DESCRIPTION OF OTHER INDEBTEDNESS

Energy Transfer Equity, L.P.

Our consolidated indebtedness as of September 30, 2013 included our existing $900 million term loan facility maturing on March 26, 2017, our existing $200 million revolving credit facility available through September 2015 and $1.8 billion in principal amount of our 2020 Notes. In addition, our subsidiaries, including ETP and Regency, had the outstanding indebtedness described below.

The failure by us and our subsidiaries to comply with the various restrictive and affirmative covenants of our respective debt agreements could require us and our subsidiaries to repay outstanding debt prior to its maturity and could negatively affect our and our subsidiaries’ ability to incur additional debt. Several of our and our subsidiaries’ debt agreements require us and our subsidiaries to measure certain financial tests and covenants quarterly and, as of September 30, 2013, we and our subsidiaries were in compliance with all of the covenants, including the financial requirements, tests, limitations and covenants related to financial ratios, under our respective existing debt agreements.

New Term Loan Facility

In connection with the Tender Offer, we intend to enter into a new senior secured term loan credit facility in an initial aggregate amount of $1 billion.

We expect the new term loan credit facility will be secured on a first-priority, equal and ratable basis with our obligations under the notes, the new revolving credit facility and the 2020 Notes, by a lien on substantially all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) all of the ETP common units and Class H units held by ETE through our ownership interests in ETE Holdings; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE holds the general partnership interests and incentive distribution rights in ETP; (iii) all of the common units of Regency held by ETE; (iv) ETE’s 100% equity interest in ETE GP Acquirer LLC; and (v) ETE GP Acquirer’s 100% interest in Regency GP LLC and Regency GP, through which ETE indirectly holds a 100% interest in Regency GP, through which ETE holds the general partnership interests and incentive distribution rights in Regency, subject to certain exceptions and permitted liens; provided that our direct and indirect interests in ETE GP Acquirer, Regency GP, ETE Common Holdings Member and ETE Common Holdings will be pledged on a first-priority basis to secure the term loan credit facility on or prior to December 31, 2013.

We expect our new term loan credit facility to contain customary covenants (in each case, subject to permitted exceptions) including, among others, the following:

 

•

a prohibition against incurring debt;

 

•

a restriction on creating liens on our assets and the assets of our subsidiaries;

 

•

restrictions on merging and selling assets outside the ordinary course of business;

 

•

restrictions on use of proceeds, investments, transactions with affiliates or change of principal business; and

 

•

a requirement that we maintain a ratio of consolidated funded debt to EBITDA (as defined in our new term loan credit facility) of not more than 6.0 to 1.0 (which ratio may be increased at our election to 7.0 to 1.0 in connection with certain specified acquisitions).

We expect our new term loan credit facility to contain customary events of default, including our failure to comply with the financial ratio described above, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require the administrative agent to declare all amounts outstanding under our new term loan credit facility to be immediately due and payable, which would materially and adversely affect our financial condition and liquidity.

We expect to use the proceeds from the new term loan credit facility (i) to refinance of our existing term loan credit facility and pay amounts under the Tender Offer, (ii) to pay the fees and expenses incurred in connection with the new term loan credit facility and related transactions and (iii) for other general partnership purposes.

 

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We cannot assure you that we will be able to enter into the new term loan credit facility on the terms set forth above or at all.

New Revolving Credit Facility

In connection with the Tender Offer, we intend to enter into a new senior secured revolving credit facility in an initial aggregate amount of $600 million.

We expect the new revolving credit facility will be secured on a first-priority, equal and ratable basis with our obligations under the notes, the new term loan credit facility and the 2020 Notes, by a lien on substantially all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) all of the ETP common units and Class H units held by ETE through our ownership interests in ETE Holdings; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE indirectly holds all of the outstanding general partnership interests and incentive distribution rights in ETP; (iii) all of the common units of Regency held by ETE; (iv) ETE’s 100% equity interest ETE GP Acquirer LLC; and (v) ETE GP Acquirer’s 100% interest in Regency GP LLC and Regency GP, through which ETE indirectly holds a 100% interest in Regency GP, through which ETE holds the general partnership interests and incentive distribution rights in Regency, subject to certain exceptions and permitted liens; provided that our direct and indirect interests in ETE GP Acquirer, Regency GP, ETE Common Holdings Member and ETE Common Holdings will be pledged on a first-priority basis to secure the term loan credit facility on or prior to December 31, 2013.

We expect our new revolving credit facility to contain customary covenants (in each case, subject to permitted exceptions) including, among others, the following:

 

•

a prohibition against incurring debt;

 

•

a restriction on creating liens on our assets and the assets of our subsidiaries;

 

•

restrictions on merging and selling assets outside the ordinary course of business;

 

•

restrictions on use of proceeds, investments, transactions with affiliates or change of principal business; and

 

•

a requirement that we maintain a ratio of consolidated funded debt to EBITDA (as defined in our new revolving credit facility) of not more than 6.0 to 1.0 (which ratio may be increased at our election to 7.0 to 1.0 in connection with certain specified acquisitions).

We expect our new revolving credit facility to contain customary events of default, including our failure to comply with the financial ratio described above, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require the administrative agent to declare all amounts outstanding under our new revolving credit facility to be immediately due and payable, which would materially and adversely affect our financial condition and liquidity.

We expect to use the proceeds from the new revolving credit facility (i) to refinance our existing revolving credit facility, (ii) to pay the fees and expenses incurred in connection with the new revolving credit facility and related transactions and (iii) for other general partnership purposes.

We cannot assure you that we will be able to enter into the new revolving credit facility on the terms set forth above or at all.

Senior Notes

The 2020 Notes represent our senior obligations and rank equally with all of our other existing and future senior indebtedness and senior to any of our future subordinated indebtedness. Our obligations under the 2020 Notes are secured on a first-priority, equal and ratable basis with our obligations under our existing term loan facility and existing revolving credit facility, by a lien on substantially all assets that from time to time secure our obligations under those facilities. The 2020 Notes are not guaranteed by any of our subsidiaries, and therefore, structurally rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

 

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Interest on the 2020 Notes is payable semi-annually on April 15 and October 15 of each year. We may redeem some or all of the 2020 Notes at any time at a price equal to 100% of the principal amount of the 2020 Notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. In addition, if we experience a change of control together with a rating decline, each as defined in the indenture governing the 2020 Notes, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase.

The indenture governing the 2020 Notes includes covenants that limit (subject to certain exceptions) our ability to incur liens; engage in affiliate transactions and enter into sale-leaseback transactions.

Energy Transfer Partners, L.P.

ETP’s indebtedness as of September 30, 2013 (not including debt of its subsidiaries set forth under “—ETP Subsidiary Debt” below) consisted of (i) a revolving credit facility that allows for borrowings of up to $2.5 billion (expandable to $3.75 billion, subject to additional lender commitments) available through October 27, 2016, unless extended, (ii) floating rate junior subordinated notes due 2066 (the “ETP junior subordinated notes”), and (iii) the following series of senior notes (collectively, the “ETP senior notes”):

 

•

$292 million in principal amount of 8.500% Senior Notes due 2014;

 

•

$750 million in principal amount of 5.950% Senior Notes due 2015;

 

•

$400 million in principal amount of 6.125% Senior Notes due 2017;

 

•

$600 million in principal amount of 6.700% Senior Notes due 2018;

 

•

$400 million in principal amount of 9.700% Senior Notes due 2019;

 

•

$450 million in principal amount of 9.000% Senior Notes due 2019;

 

•

$700 million in principal amount of 4.150% Senior Notes due 2020;

 

•

$800 million in principal amount of 4.650% Senior Notes due 2021;

 

•

$1 billion in principal amount of 5.200% Senior Notes due 2022;

 

•

$800 million in principal amount of 3.600% Senior Notes due 2023;

 

•

$277.5 million in principal amount of 7.600% Senior Notes due 2024;

 

•

$350 million in principal amount of 4.900% Senior Notes due 2024

 

•

$266.7 million in principal amount of 8.250% Senior Notes due 2029;

 

•

$400 million in principal amount of 6.625% Senior Notes due 2036;

 

•

$550 million in principal amount of 7.500% Senior Notes due 2038;

 

•

$700 million in principal amount of 6.050% Senior Notes due 2041;

 

•

$1 billion in principal amount of 6.500% Senior Notes due 2042;

 

•

$450 million in principal amount of 5.150% Senior Notes due 2043; and

 

•

$450 million in principal amount of 5.950% Senior Notes due 2043.

In addition to the above indebtedness, ETP is a co-obligor of the following outstanding senior notes and debentures of Sunoco (collectively, the “Sunoco senior notes”):

 

•

$250 million in principal amount of 9.625% Senior Notes due 2015;

 

•

$400 million in principal amount of 5.75% Senior Notes due 2017;

 

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•

$250 million in principal amount of 4 7/8% Senior Notes due 2014; and

 

•

$65 million in principal amount of 9.00% Debentures due 2024.

ETP’s other subsidiaries, Transwestern Pipeline Company, LLC (“Transwestern”), Southern Union, Panhandle and Sunoco Logistics (through its subsidiaries, Sunoco Logistics Partners Operations L.P. (“Sunoco Operations”) and Sunoco Marketing), also have outstanding debt as described below under “—ETP Subsidiary Debt.”

Revolving Credit Facility

On October 27, 2011, ETP amended and restated its revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, swingline lender and an LC issuer, Bank of America, N.A., as an LC issuer, and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and RBS Securities Inc., as joint lead arrangers and joint book managers, and certain other agents and lenders. The revolving credit facility provides for $2.5 billion of revolving credit capacity that is expandable to $3.75 billion at ETP’s option (subject to obtaining lender commitments for the additional borrowing capacity). The revolving credit facility matures on October 27, 2016, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments under the revolving credit facility). Amounts borrowed under the revolving credit facility bear interest at a rate based on either a LIBOR rate or a base rate, at ETP’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to ETP’s senior, unsecured, non-credit enhanced long-term debt. The applicable margin for LIBOR rate loans ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.125% to 0.750%. The revolving credit facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.5 billion unless expanded to $3.75 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. ETP may prepay the indebtedness under the revolving credit facility at any time at ETP’s option without penalty (other than Eurodollar loan breakage costs, if any). The commitment fee payable on the unused portion of the revolving credit facility varies based on ETP’s credit rating and ranges from 0.175% to 0.300%. Currently, the applicable rate for commitment fees is 0.25%.

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

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

As of September 30, 2013, there were no borrowings outstanding under the revolving credit facility. The total amount available for additional borrowing under the revolving credit facility, as of September 30, 2013, was $2.50 billion. The indebtedness under the revolving credit facility is unsecured and is not guaranteed by any of ETP’s subsidiaries. The indebtedness under the revolving credit facility is and will be pari passu with ETP’s other current and future unsecured debt.

 

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Senior Notes and Sunoco Senior Notes

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

Each series of the ETP senior notes (other than the 4.150% Senior Notes due 2020, 4.650% Senior Notes due 2021, 5.200% Senior Notes due 2022, 3.600% Senior Notes due 2023, 7.600% Senior Notes due 2024, 4.900% Senior Notes due 2024, 8.250% Senior Notes due 2029, 6.050% Senior Notes due 2041, 6.500% Senior Notes due 2042, 5.150% Senior Notes due 2043 and 5.950% Senior Notes due 2043) is redeemable, in whole or in part, at any time at ETP’s option, at a price equal to 100% of the principal amount of such senior notes, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. Each of the 4.650% Senior Notes due 2021, 5.200% Senior Notes due 2022, 3.600% Senior Notes due 2023, 6.050% Senior Notes due 2041, 6.500% Senior Notes due 2042, 5.150% Senior Notes due 2043 and 5.950% Senior Notes due 2043 is redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium if the redemption occurs before the date that is six months prior to maturity or (ii) at par if the redemption occurs on or after the date that is six months prior to maturity, in each case plus accrued and unpaid interest, if any, to the redemption date. Each of the 4.90% Senior Notes due 2024, the 7.600% Senior Notes due 2024 and the 8.250% Senior Notes due 2029 is redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes, plus a make-whole premium if the redemption occurs before the date that is three months prior to maturity or (ii) at par if the redemption occurs on or after the date that is three months prior to maturity, in each case, plus accrued and unpaid interest, if any, to the redemption date. The 4.150% Senior Notes due 2020 are redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes, plus a make-whole premium if the redemption occurs before the date that is two months prior to maturity or (ii) at par if the redemption occurs on or after the date that is two months prior to maturity, in each case, plus accrued and unpaid interest, if any, to the redemption date.

The Sunoco senior notes (other than the 9.00% Debentures due 2024) are redeemable, in whole or in part, at any time at ETP’s and Sunoco’s option, at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. The 9.00% Debentures due 2024 are not redeemable prior to maturity.

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

Junior Subordinated Notes

The ETP junior subordinated notes, which mature on November 1, 2066, are unsecured and rank junior and are subordinated, to the extent and in the manner set forth in the indenture governing such notes, in right of payment and upon liquidation to the prior payment in full of all of ETP’s senior indebtedness.

Interest on the ETP junior subordinated notes accrues from June 24, 2013, at a floating rate calculated as three-month LIBOR for the related interest period plus 3.0175% per annum, reset quarterly, and ETP pays interest quarterly in arrears on February 1, May 1, August 1 and November 1 of each year. Interest on the ETP junior subordinated notes compounds on the outstanding principal balance and any accrued and unpaid interest. So long as no event of default with respect to the ETP junior subordinated notes is continuing, ETP may elect to defer interest payments on the ETP junior subordinated notes for a period of up to 10 consecutive years (but not beyond the maturity date or redemption date of the notes). During any such deferral period interest will continue to accrue on the ETP junior subordinated notes at the applicable floating rate.

 

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ETP has the option to redeem the ETP junior subordinated notes in whole or in part and from time to time at a redemption price equal to 100% of the principal amount of the notes to be redeemed plus accrued and unpaid interest thereon to, but excluding, the redemption date.

During any period in which interest payments are being deferred, ETP may not declare or pay dividends on, or redeem, purchase, or acquire, any of its partnership securities, make certain interest or principal payments or make certain guarantee payments with respect to ETP’s indebtedness or guarantees ranking junior to or pari passu with the ETP junior subordinated notes. Accordingly, during such period in which interest payments are being deferred, ETP will be restricted from paying distributions to ETE with respect to ETE’s equity interest in ETP. The indenture governing the ETP junior subordinated notes does not restrict ETP or its subsidiaries from incurring additional indebtedness, creating liens on ETP’s property for any purpose or paying distributions on ETP’s equity interests or purchasing or redeeming its equity interests (except as described in the previous sentence), nor does it require the maintenance of any financial ratios or specified levels of net worth or liquidity. In addition, the indenture does not contain any provisions that would require ETP to repurchase or redeem or otherwise modify the terms of the ETP junior subordinated notes upon a change in control or other events involving ETP. Events of default under the indenture include (i) non-payment of principal when due, (ii) non-payment of interest within 30 days after such interest is due (other than permitted interest deferrals), or (iii) certain events of bankruptcy, insolvency or reorganization. With respect to the ETP junior subordinated notes, a failure to comply with the other covenants under the indenture does not constitute an event of default. Upon the occurrence of an event of default under the indenture, the trustee or the holders of at least 25% of the principal amount of the ETP junior subordinated notes will have the right to declare the principal amount of the notes, and any accrued interest, immediately due and payable.

ETP Subsidiary Debt

Transwestern

As of September 30, 2013, Transwestern had the following outstanding series of unsecured notes (collectively, the “Transwestern notes”):

 

•

$88 million in principal amount of 5.39% Senior Notes due 2014;

 

•

$125 million in principal amount of 5.54% Senior Notes due 2016;

 

•

$82 million in principal amount of 5.64% Senior Notes due 2017;

 

•

$175 million in principal amount of 5.36% Senior Notes due 2020;

 

•

$150 million in principal amount of 5.89% Senior Notes due 2022;

 

•

$175 million in principal amount of 5.66% Senior Notes due 2024; and

 

•

$75 million in principal amount of 6.16% Senior Notes due 2037.

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

 

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Southern Union and Panhandle Debt

As of September 30, 2013, Southern Union’s indebtedness consisted of the following senior and junior subordinated notes:

 

•

$82.3 million in principal amount of 7.60% Senior Notes due 2024;

 

•

$33.3 million in principal amount of 8.25% Senior Notes due 2029; and

 

•

$54 million in principal amount of Floating Rate Junior Subordinated Notes due 2066.

 

•

As of September 30, 2013, the indebtedness of Panhandle, a wholly owned subsidiary of Southern Union, consisted of the following series of senior notes:

 

•

$300 million in principal amount of 6.20% Senior Notes due 2017;

 

•

$150 million in principal amount of 8.125% Senior Notes due 2019;

 

•

$66 million in principal amount of 7.00% Senior Notes due 2029; and

 

•

$400 million in principal amount of 7.00% Senior Notes due 2018.

Southern Union

Senior Notes. Southern Union’s senior notes represent its senior unsecured obligations and rank equally with all of its other existing and future unsecured and unsubordinated indebtedness. Southern Union’s senior notes are not guaranteed by any of Southern Union’s subsidiaries, and therefore, structurally rank junior to all indebtedness and other liabilities of its existing and future subsidiaries. Southern Union’s senior notes are not redeemable prior to their respective maturity dates. In June 2013, Southern Union entered into a supplemental indenture to the indenture governing each series of senior notes to remove substantially all of the restrictive covenants and certain events of default contained therein and to modify certain other provisions.

Junior Notes. Southern Union’s obligations under the junior notes are subordinated and junior in right of payment to all of its other indebtedness, except any indebtedness that by its terms is subordinated to, or ranks on an equal basis with, the junior notes. In addition, because the notes are not guaranteed by any of Southern Union’s subsidiaries, the holders of junior notes generally have a junior position in right of payment to claims of creditors of Southern Union’s subsidiaries and joint ventures. Subject to Southern Union’s right to defer interest payments on the junior notes on one or more occasions for up to 10 consecutive years, interest on the junior notes is payable quarterly. Beginning on November 1, 2011, the interest rate is a floating rate based on three-month LIBOR plus 301.75 basis points, and is reset quarterly. Any deferred interest payments will accumulate additional interest at a rate equal to the interest rate then applicable to the junior notes, to the extent permitted by law. Southern Union may redeem the junior notes, in whole or in part, at any time at par, plus accrued and unpaid interest, if any, to the redemption date. In June 2013, Southern Union entered into a supplemental indenture to the indenture governing the junior notes to remove substantially all of the restrictive covenants and certain events of default contained therein and to modify certain other provisions.

Panhandle

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

 

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equity interests (excluding distributions or redemptions made so long as no event of default has occurred and is continuing and Panhandle is in compliance with its fixed charge coverage ratio covenant and leverage ratio covenant in the indenture); incur liens; enter into sale and leaseback transactions; enter into certain types of affiliates transactions and dispose of assets.

Sunoco Logistics Debt

As of September 30, 2013, Sunoco Logistics’ indebtedness consisted of a $350 million unsecured credit facility of its wholly owned subsidiary, Sunoco Operations, maturing in August 2016 (the “SXL 2016 credit facility”), and the following series of senior notes of Sunoco Operations:

 

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$175 million in principal amount of 8.75% Senior Notes due 2014;

 

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$175 million in principal amount of 6.125% Senior Notes due 2016;

 

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$250 million in principal amount of 5.50% Senior Notes due 2020;

 

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$300 million in principal amount of 4.65% Senior Notes due 2022;

 

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$350 million in principal amount of 3.45% Senior Notes due 2023;

 

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$250 million in principal amount of 6.85% Senior Notes due 2040;

 

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$300 million in principal amount of 6.10% Senior Notes due 2042; and

 

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$350 million in principal amount of 4.95% Senior Notes due 2043.

In addition, Sunoco Marketing had outstanding a $200 million 364-day revolving unsecured credit facility that matured in August 2013 and was replaced by a new 364-day revolving unsecured credit facility on August 9, 2013 (the “SXL 2014 credit facility”). As of September 30, 2013, West Texas Gulf Pipe Line Company (“West Texas Gulf”), an entity in which Sunoco Logistics has a controlling financial interest, also had outstanding a $35 million revolving credit facility maturing in April 2015.

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

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

 

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As of September 30, 2013, there were no outstanding borrowings and no letters of credit issued under the SXL 2016 credit facility.

SXL 2014 Credit Facility. Sunoco Marketing entered into the SXL 2014 credit facility with Citibank, N.A., as administrative agent, Barclays Bank PLC, as syndication agent, TD Bank, N.A. and Wells Fargo Bank, N.A., as co-documentation agents, and certain other lenders on August 9, 2013. The SXL 2014 credit facility provides for $200 million of revolving credit capacity and matures on August 7, 2014. Sunoco Marketing’s obligations under the SXL 2014 credit facility are guaranteed by Sunoco Operations and Sunoco Logistics. Amounts borrowed under the SXL 2014 credit facility bear interest at a rate based on either a LIBOR rate or a base rate, at Sunoco Marketing’s option, plus an applicable rate. The applicable rate used in connection with the interest rates and facility fees, respectively, are based on the credit ratings assigned to Sunoco Operations’ non-credit enhanced, senior unsecured long-term debt. The applicable rate for LIBOR rate loans ranges from 0.940% to 1.600% and the applicable rate for base rate loans ranges from 0% to 0.600%. The applicable rate for the facility fee payable on the unused portion of the SXL 2014 credit facility ranges from 0.060% to 0.150%. Sunoco Marketing may prepay the indebtedness under the SXL 2014 credit facility at any time at its option without premium or penalty provided that certain conditions are met.

The SXL 2014 credit facility contains similar covenants as those contained in the SXL 2016 credit facility described above.

Senior Notes. Sunoco Operations’ obligations under its senior notes are guaranteed by Sunoco Logistics. The Sunoco Operations’ senior notes represent Sunoco Operations’ senior unsecured obligations and rank equally in right of payment with all of its existing and future unsecured and unsubordinated indebtedness, including debt under the SXL 2016 credit facility and the SXL 2014 credit facility. Sunoco Logistics’ guarantee of the senior notes ranks equally in right of payment with its existing and future unsecured and unsubordinated indebtedness, including its guarantee of debt under the SXL 2016 credit facility and the SXL 2014 credit facility. Each series of Sunoco Operations’ senior notes (other than the 3.45% Senior Notes due 2023 and the 4.95% Senior Notes due 2043) is redeemable, in whole or in part, at any time at Sunoco Operations’ option, at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. Each of the 3.45% Senior Notes due 2023 and the 4.95% Senior Notes due 2043 is redeemable, in whole or in part, (i) at a price equal to 100% of the principal amount of such senior notes plus a make-whole premium if the redemption occurs before the date that is six months prior to maturity or (ii) at par if the redemption occurs on or after the date that is six months prior to maturity, in each case plus accrued and unpaid interest, if any, to the redemption date. The senior notes were issued under an indenture containing covenants that limit, subject to certain exceptions, the ability of Sunoco Operations and its subsidiaries to create liens; engage in sale and leaseback transactions and merger or consolidate with another entity or sell substantially all of their assets.

Unconsolidated Joint Venture Debt

As of September 30, 2013, ETP’s unconsolidated joint ventures, FEP, Citrus and FGT, had the following indebtedness outstanding:

 

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$600 million term loan of FEP maturing on July 8, 2016, with an effective interest rate of 1.69%;

 

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$144 million of borrowings outstanding under Citrus’ $200 million revolving credit facility maturing on November 2, 2015, subject to certain extension rights, with a weighted average interest rate of 1.59%;

 

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$500 million construction term loan of Citrus maturing on October 8, 2029, with an effective interest rate of 9.39%; and

 

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$1.8 billion in principal amount of senior notes of FGT.

 

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FGT has also entered into a $200 million revolving credit facility maturing on November 2, 2015, subject to FGT’s right to extend the maturity date by one year (which right may not be exercised more than twice). As of September 30, 2013, there were no borrowings outstanding under the FGT revolving credit facility.

Regency Energy Partners LP

Regency’s indebtedness as of September 30, 2013 consisted of (i) a revolving credit facility of its wholly owned subsidiary, Regency Gas Services LP (“Regency Gas”), that allows for borrowings of up to $1.2 billion, with $50 million of availability for letters of credit and a $300 million uncommitted incremental facility, available through May 21, 2018 (the “Regency credit facility”), and (ii) the following series of senior notes (collectively, the “Regency senior notes”):

 

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$600 million in principal amount of 6  7/8% Senior Notes due 2018;

 

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$500 million in principal amount of 6  1/2% Senior Notes due 2021;

 

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$700 million in principal amount of 5  1/2% Senior Notes due 2023;

 

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$600 million in principal amount of 4  1/2% Senior Notes due 2023; and

 

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$400 million in principal amount of 5.75% Senior Notes due 2020.

Revolving Credit Facility

Effective May 21, 2013, the Regency credit facility has aggregate commitments to $1.2 billion, with $50 million of availability for letters of credit and a $300 million uncommitted incremental facility. The maturity date of the Regency credit facility is May 21, 2018. The obligations under the Regency credit facility are secured by substantially all of Regency’s assets and are guaranteed by Regency and substantially all of Regency’s subsidiaries.

Interest on loans is calculated using either an alternate base rate or a LIBOR-based rate. The alternate base rate used to calculate interest on base rate loans is calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.500% and an adjusted one-month LIBOR rate plus 1.000%. The applicable margin ranges from 0.625% to 1.500% for base rate loans, 1.625% to 2.500% for LIBOR-based loans, and a commitment fee of 0.300% to 0.450%, in each case based upon Regency’s consolidated leverage ratio. Regency must also pay a participation fee for each revolving lender participating in letters of credit ranging from 1.625% to 2.500% per annum of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of the letter of credit exposure. As of September 30, 2013, the Regency credit facility had a balance outstanding of $176 million in revolving credit loans and approximately $15 million in letters of credit. The total amount available under the Regency credit facility, as of September 30, 2013, which was reduced by any letters of credit, was approximately $1.01 billion, and the weighted average interest rate on the total amount outstanding as of September 30, 2013 was 2.19%.

Regency’s credit agreement contains the following financial covenants:

 

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consolidated total leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement, (a) ending on or prior to March 31, 2015 must not exceed 5.50 to 1 and (b) ending after March 31, 2015 must not exceed 5.25 to 1;

 

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interest coverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement, must not be less than 2.50 to 1; and

 

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consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement, must not exceed 3.25 to 1.

 

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Regency’s credit agreement also contains various covenants that limit among other things, Regency Gas’ and the guarantors’ ability to incur indebtedness; authorize, declare, pay or set aside funds for purposes of making dividends; grant liens; enter into sale and leaseback transactions; make certain investments, loans and advances; dissolve or enter into a merger or consolidation; enter into asset sales or make acquisitions; enter into certain types of transactions with affiliates; prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement); issue capital stock or create subsidiaries; or engage in any business other than those businesses in which they were engaged at the time of the effectiveness of the Regency credit facility or reasonable extensions thereof.

Senior Notes

Interest on the Regency senior notes is payable semi-annually in arrears on June 1 and December 1, with respect to the 6 ⁷/₈% Senior Notes due 2018, on January 15 and July 15, with respect to the 6 ¹/₂% Senior Notes due 2021, on April 15 and October 15, with respect to the 5 ¹/₂% Senior Notes due 2023, on May 1 and November 1, with respect to the 4 ¹/₂% Senior Notes due 2023, and on March 1 and September 1, with respect to the 5.75% Senior Notes due 2020. Each series of Regency senior notes is guaranteed by certain of Regency’s subsidiaries.

Each series of the Regency senior notes is redeemable at any time prior to (i) December 1, 2014, with respect to the 6 ⁷/₈% Senior Notes due 2018, (ii) July 15, 2016, with respect to the 6 ¹/₂% Senior Notes due 2021, (iii) October 15, 2017, with respect to the 5 ¹/₂% Senior Notes due 2023, (iv) August 1, 2023, with respect to the 4 ¹/₂% Senior Notes due 2023 and (v) June 1, 2020, with respect to the 5.75% Senior Notes due 2020, in each case at a price equal to 100% of the principal amount of the applicable series of existing senior notes, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date. On or after (i) December 1, 2014, with respect to the 6 ⁷/₈% Senior Notes due 2018, (ii) July 15, 2016, with respect to the 6 ¹/₂% Senior Notes due 2021 and (iii) October 15, 2017, with respect to the 5 ¹/₂% Senior Notes due 2023, the applicable series of existing senior notes are redeemable in whole or in part, at fixed redemption prices plus accrued and unpaid interest, if any, to the redemption date. On or after (i) August 1, 2023, with respect to the 4 ¹/₂% Senior Notes due 2023, and (ii) June 1, 2020, with respect to the 5.75% Senior Notes due 2020, are redeemable in whole or in part, at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. Further, at any time prior to (i) December 1, 2013, with respect to the 6 ⁷/₈% Senior Notes due 2018, (ii) July 15, 2014, with respect to the 6 ¹/₂% Senior Notes due 2021 and (iii) October 15, 2015, with respect to the 5 ¹/₂% Senior Notes due 2023, we may redeem up to 35% of such series of notes in an amount equal to the net cash proceeds we receive from certain qualified equity offerings.

Upon a change of control followed by a ratings downgrade within 90 days of a change of control, each noteholder of the Regency senior notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any.

The indentures governing the Regency senior notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to incur additional indebtedness; pay distributions on, or repurchase or redeem Regency’s equity interests; make certain investments; incur liens; enter into certain types of transactions with affiliates; and sell assets or consolidate or merge with or into other companies.

If the Regency senior notes achieve investment grade ratings by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants. At September 30, 2013, Regency was in compliance with these covenants.

 

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Unconsolidated Joint Venture Debt

As of September 30, 2013, Regency’s unconsolidated joint ventures HPC and MEP had outstanding the following indebtedness:

 

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$445 million of borrowings outstanding under HPC’s revolving credit facility maturing on September 10, 2018, with a weighted average interest rate of 2.18%;

 

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$16 million of borrowings outstanding under MEP’s revolving credit facility maturing on February 15, 2014, with a weighted average interest rate of 2.19%;

As of September 30, 2013 Regency’s unconsolidated joint ventures Lone Star and Ranch JV had no outstanding indebtedness.

Contingent Support

In connection with the closing of the contribution of ETP’s propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022.

 

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DESCRIPTION OF NOTES

ETE will issue the notes as a new series of its debt securities described in the accompanying prospectus. The notes will be issued under an indenture dated as of September 20, 2010 , as supplemented by the fourth supplemental indenture establishing the notes to be dated as of the closing of this offering (collectively, the “indenture”), between itself and U.S. Bank National Association, as trustee (the “Trustee”). This description is a summary of the material provisions of the notes, the indenture and the Notes Collateral Documents (as defined below). The summary of selected provisions of the notes and the indenture referred to below supplements, and to the extent inconsistent supersedes and replaces, the description of the general terms and provisions of the debt securities and the indenture contained in the accompanying prospectus under the caption “Description of Debt Securities.” This description does not restate those agreements and instruments in their entirety. You should refer to the notes and the indenture, forms of which are available as set forth below under “Where You Can Find More Information,” for a complete description of our obligations and your rights.

You can find the definitions of various terms used in this description under “— Definitions” below. In this description, the terms “ETE,” “we,” “us” and “our” refer only to Energy Transfer Equity, L.P. and not to any of its Subsidiaries or Affiliates. The registered holder of a note (each, a “Holder”) will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.

General

The notes will:

 

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be general senior obligations of ETE, ranking equally in right of payment with all other existing and future unsubordinated indebtedness of ETE;

 

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rank senior in right of payment to all future subordinated indebtedness of ETE, if any;

 

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be secured by a Lien on the Collateral to the extent described below under “— Security for the Notes”;

 

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initially be issued in an aggregate principal amount of $400,000,000;

 

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mature on             , 2024;

 

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be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof;

 

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bear interest at an annual rate of    %; and

 

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be redeemable at any time at our option at the redemption price described below under “— Optional Redemption.”

The notes constitute a series of debt securities under the indenture. The indenture does not limit the amount of debt securities we may issue under the indenture from time to time in one or more series. We may in the future issue additional debt securities under the indenture in addition to the notes.

Interest

Interest on the notes will accrue at an annual rate of     % from and including             , 2013 or from and including the most recent interest payment date to which interest has been paid or provided for. We will pay interest on the notes in cash semi-annually in arrears on                and                of each year, beginning             , 2014. We will make interest payments to the Holders of record at the close of business on                or             , as applicable, before the next interest payment date.

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. If a payment date is a Legal Holiday at a place of payment, payment may be made at that place on the next succeeding day that is not a Legal Holiday, and no interest shall accrue on such payment for the intervening period.

 

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Methods of Receiving Payments on the Notes

If a Holder of notes has given wire transfer instructions to ETE, ETE will pay all principal, premium, if any, and interest on that Holder’s notes in accordance with those instructions. All other payments on the notes will be made at the office or agency of the paying agent and registrar, unless we elect to make interest payments by check mailed to the Holders at their address set forth in the register of Holders.

Further Issuances

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

Paying Agent and Registrar

Initially, the Trustee will act as paying agent and registrar for the notes. We may change the paying agent or registrar for the notes without prior notice to the Holders of the notes, and we or any of the Restricted Subsidiaries may act as paying agent or registrar; provided, however, that we will be required to maintain at all times an office or agency in the Borough of Manhattan, The City of New York (which may be an office of the Trustee or an affiliate of the Trustee or the registrar or a co-registrar for the notes) where the notes may be presented for payment and where notes may be surrendered for registration of transfer or for exchange and where notices and demands to or upon us in respect of the notes and the indenture may be served. We may also from time to time designate one or more additional offices or agencies where the notes may be presented or surrendered for any or all such purposes and may from time to time rescind such designations; provided, however, that no such designation or rescission will in any manner relieve us of our obligation to maintain an office or agency in the Borough of Manhattan, The City of New York for such purposes.

The registrar and the Trustee may require a Holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of the notes, and ETE may require a Holder to pay any taxes and fees required by law or permitted by the indenture. ETE will not be required to transfer or exchange any note (or portion of a note) selected for redemption. Also, ETE will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

Subsidiary Guarantees

The notes initially will not be guaranteed by any of our Subsidiaries. However, if at any time following the Issue Date, any Subsidiary of ETE guarantees or becomes a co-obligor with respect to any obligations of ETE in respect of any Indebtedness, or if at any time following the Issue Date any Restricted Subsidiary of ETE otherwise incurs any Indebtedness (excluding, for the avoidance of doubt, any intercompany Indebtedness between ETE or any Subsidiary or Subsidiaries of ETE on the one hand and such Restricted Subsidiary on the other), then ETE will cause such Subsidiary or Restricted Subsidiary, as the case may be, to promptly execute and deliver to the Trustee a supplemental indenture to the indenture in a form satisfactory to the Trustee pursuant to which such Subsidiary or Restricted Subsidiary will guarantee all obligations of ETE with respect to the notes on the terms provided for in the indenture. The Subsidiary Guarantees will be joint and several obligations of the Subsidiary Guarantors. The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable law.

The Subsidiary Guarantee of any Subsidiary Guarantor may be released under certain circumstances. If no default has occurred and is continuing under the indenture, and to the extent not otherwise prohibited by the indenture, a Subsidiary Guarantor will be unconditionally released and discharged from its Subsidiary Guarantee:

 

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automatically upon any direct or indirect sale, transfer or other disposition, whether by way of merger or otherwise, to any Person that is not an Affiliate of ETE, of (a) all of the Capital Stock representing ownership of such Subsidiary Guarantor or (b) all or substantially all the assets of such Subsidiary Guarantor;

 

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•

(a) in the case of a Subsidiary Guarantor that is not a Restricted Subsidiary, following delivery by ETE to the Trustee of an officer’s certificate to the effect that such Subsidiary Guarantor has been released from all guarantees or obligations in respect of any Indebtedness of ETE and (b) in the case of a Subsidiary Guarantor that is a Restricted Subsidiary, following delivery by ETE to the Trustee of an officer’s certificate to the effect that such Subsidiary Guarantor has been released from all guarantees or obligations in respect of any Indebtedness; or

 

•

upon legal defeasance or satisfaction and discharge of the indenture as provided below under the caption “— Defeasance and Discharge.”

If at any time following any release of a Subsidiary (that is not a Restricted Subsidiary) from its Subsidiary Guarantee pursuant to the second bullet point in the preceding paragraph, such Subsidiary again guarantees or becomes a co-obligor with respect to any obligations of ETE in respect of any Indebtedness of ETE, then ETE will cause such Subsidiary to again become a Subsidiary Guarantor by executing and delivering a supplemental indenture to the indenture in a form satisfactory to the Trustee and thus guarantee the notes and all other obligations of ETE under the indenture, in accordance with the terms of the indenture. If at any time following any release of a Subsidiary (that is a Restricted Subsidiary) from its Subsidiary Guarantee pursuant to the second bullet point in the preceding paragraph, such Subsidiary again incurs any Indebtedness (excluding, for the avoidance of doubt, any intercompany Indebtedness between ETE or any Subsidiary of Subsidiaries of ETE on the one hand and such Restricted Subsidiary on the other), then ETE will cause such Subsidiary to again become a Subsidiary Guarantor by executing and delivering a supplemental indenture to the indenture in a form satisfactory to the Trustee and thus guarantee the notes and all other obligations of ETE under the indenture, in accordance with the terms of the indenture.

Ranking

The notes will be senior obligations of ETE and will be secured on a first-priority basis by a Lien on the Collateral, subject to certain liens permitted under the indenture, which Liens are intended to be pari passu with the Liens securing the Credit Agreements. The notes:

 

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will rank senior in right of payment to all future obligations of ETE that are, by their terms, expressly subordinated in right of payment to the notes and pari passu in right of payment with all existing and future senior obligations of ETE that are not so subordinated;

 

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will be structurally subordinated to all liabilities and preferred equity of Subsidiaries of ETE that are not Subsidiary Guarantors; and

 

•

will be guaranteed by each Subsidiary of ETE that in the future is required to become a Subsidiary Guarantor.

Each Subsidiary Guarantee, if any, will be a senior obligation of the relevant Subsidiary Guarantor and will be secured on a first-priority basis by a Lien on the Collateral owned by such Subsidiary Guarantor, subject to certain liens permitted under the indenture, which Liens are intended to be pari passu with the Liens securing the Credit Agreements and will rank senior in right of payment to all future obligations of such Subsidiary Guarantor that are, by their terms, expressly subordinated in right of payment to such Subsidiary Guarantee and pari passu in right of payment with all existing and future senior obligations of such Subsidiary Guarantor that are not so subordinated.

The notes will be effectively subordinated to all existing and future obligations, including Indebtedness, of any Subsidiaries of ETE that do not guarantee the notes. Claims of creditors of these Subsidiaries, including trade creditors, will generally have priority as to the assets of these Subsidiaries over the claims of ETE and the holders of ETE’s Indebtedness, including the notes. As of September 30, 2013, ETE’s Subsidiaries had outstanding approximately $19.3 billion of indebtedness, all of which would rank effectively senior to the notes. Furthermore, the notes and each Subsidiary Guarantee will be effectively subordinated to any Indebtedness of

 

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ETE and the applicable Subsidiary Guarantor secured by liens permitted under the indenture to the extent of the value of the assets securing such Indebtedness.

Optional Redemption

The notes will be redeemable, at our option, at any time in whole, or from time to time in part, at a price equal to the greater of:

 

•

100% of the principal amount of the notes to be redeemed; and

 

•

the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Yield plus 50 basis points;

plus, in either case, accrued interest to the redemption date.

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

We also have the option at any time on or after                     , 2023 (which is the date that is three months prior to the maturity date of the notes) to redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest thereon to the redemption date.

Notes called for redemption become due on the redemption date. Notices of redemption will be mailed at least 30 but not more than 60 days before the redemption date to each Holder of the notes to be redeemed at its registered address. The notice of redemption for the notes will state, among other things, the amount of notes to be redeemed, the redemption date, the method of calculating the redemption price and each place that payment will be made upon presentation and surrender of notes to be redeemed. Unless we default in payment of the redemption price, interest will cease to accrue on any notes that have been called for redemption on the redemption date. For purposes of determining the redemption price, the following definitions are applicable:

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

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

 

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

“Independent Investment Banker” means Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Citigroup Global Markets Inc. and Goldman, Sachs & Co. and their respective successors or, if any such firm is not willing and able to select the applicable Comparable Treasury Issue, an independent investment banking institution of national standing appointed by ETE and reasonably acceptable to the Trustee.

“Reference Treasury Dealer” means (a) each of Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Citigroup Global Markets Inc. and Goldman, Sachs & Co. and their respective successors, and (b) one other primary U.S. government securities dealer in the United States selected by ETE (each, a “Primary Treasury Dealer”); provided, however, that if any of the foregoing shall resign as a Reference Treasury Dealer or cease to be a U.S. government securities dealer, ETE will substitute therefor another Primary Treasury Dealer.

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

Selection and Notice

If less than all of the notes are to be redeemed at any time, the Trustee will select notes for redemption on a pro rata basis by lot or by such other manner as the Trustee shall deem fair and appropriate unless otherwise required by law or applicable stock exchange requirements. No notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture.

Any redemption and notice of redemption may, at ETE’s discretion, be subject to the satisfaction of one or more conditions precedent (including, in the case of a redemption related to an equity offering, the consummation of such equity offering).

If the optional redemption date is on or after an interest record date and on or before the related interest payment date, the accrued and unpaid interest will be paid to the Person in whose name the note is registered at the close of business on such record date, and no additional interest will be payable to Holders whose notes will be subject to redemption by ETE.

If any note is to be redeemed in part only, the notice of redemption that relates to such note shall state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest will cease to accrue on notes or portions of notes called for redemption, unless ETE defaults in making the redemption payment.

Open Market Purchases; No Mandatory Redemption or Sinking Fund

We may at any time and from time to time purchase notes in the open market or otherwise. We are not required to make mandatory redemption or sinking fund payments with respect to the notes.

 

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Security for the Notes

General

The Revolving Credit Agreement Obligations, the Term Loan Agreement Obligations and the Existing Note Obligations are secured on a first-priority basis with Liens on the Collateral. The notes will be secured to the same extent as such obligations are so secured until such time as the aggregate principal amount of all Indebtedness then outstanding under the Revolving Credit Agreement Obligations and the Term Loan Agreement Obligations secured by such Liens, together with all Attributable Indebtedness from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by clauses (1) through (3), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below), does not exceed the greater of (x) $250.0 million and (y) 10.0% of Net Tangible Assets; provided that the Liens securing obligations relating to the 2020 Notes have been released concurrently with the release of the Liens securing the notes. Upon any such release of the Collateral, the “—Limitations on Liens” covenant will continue to govern the incurrence of Liens by ETE and its Restricted Subsidiaries.

The Liens securing the notes are intended to be shared equally and ratably (subject to Permitted Liens) with the holders of other Senior Obligations, which include the Revolving Credit Agreement Obligations, the Term Loan Agreement Obligations, the Existing Note Obligations and any future Additional Senior Secured Debt Obligations. As of the Issue Date, ETE’s only Senior Obligations will be the Revolving Credit Agreement Obligations, the Term Loan Agreement Obligations, the Existing Note Obligations and the Note Obligations.

The assets securing the Senior Obligations will include substantially all of the tangible and intangible assets of ETE and its Restricted Subsidiaries (other than ETP GP and Regency GP, which are not pledgors), which include (i) approximately 49.6 million ETP common units and approximately 50.2 million ETP Class H units which are held through our ownership interests in ETE Common Holdings Member and ETE Common Holdings; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE indirectly holds all of the outstanding general partnership interests in ETP and 100% of the outstanding incentive distribution rights in ETP; (iii) approximately 26.3 million Regency common units held by ETE; (iv) ETE’s 100% interest in ETE GP Acquirer; and (v) ETE GP Acquirer’s 100% interest in Regency GP LLC and Regency GP, through which ETE indirectly holds a 100% interest in Regency GP, through which ETE holds the general partnership interests and incentive distribution rights in Regency; provided that our direct and indirect interests in ETE GP Acquirer, Regency GP, ETE Common Holdings Member and ETE Common Holdings will be pledged on a first-priority basis to secure the Revolving Credit Agreement Obligations, the Term Loan Agreement Obligations, the Existing Note Obligations and the notes on or prior to December 31, 2013. Notwithstanding the foregoing, if the documents governing any of the Collateral described above contain enforceable restrictions on assignment or transfer of any rights of ETE or any Restricted Subsidiary thereunder, then the Liens on the Collateral will be limited only to the extent necessary to comply with those enforceable restrictions. Pursuant to the Credit Agreements, the Existing Indenture, the indenture and the Collateral Documents, the Obligors also will be able to incur, without the consent of the Holders of the notes, Additional Senior Secured Debt in the future, which will be secured by Liens on the Collateral. Those Liens will rank pari passu with the Liens securing the Note Obligations, and the amount of such Additional Senior Secured Debt and other obligations could be significant. Any such Indebtedness will constitute Senior Obligations. So long as any Senior Obligations remain outstanding and are secured, the Senior Secured Parties will have rights and remedies with respect to the Collateral that, if exercised, could also adversely affect the value of the Collateral on behalf of the Holders of the notes.

Upon the occurrence of an Event of Default, the proceeds from the sale of Collateral may be insufficient to satisfy ETE’s obligations under the notes and the Restricted Subsidiaries’ obligations under any Subsidiary Guarantees. No appraisals of any of the Collateral have been prepared in connection with this offering. Moreover, the amount to be received upon such sale would be dependent upon numerous factors, including market conditions at the time of the sale, as well as the timing and manner of the sale. By its nature, all or some of the Collateral will be illiquid and may have no readily ascertainable market value. Accordingly, there can be

 

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no assurance that the Collateral, if saleable, can be sold in a short period of time. See “Risk Factors — Risks Related to the Notes.”

Liens on the Collateral

ETE, the Restricted Subsidiaries (other than ETP GP and Regency GP) and certain Senior Loan Parties will enter into the Bank Collateral Documents in connection with the Credit Agreements, defining the terms of the security interests on the Collateral that secure the payment and performance when due of all of the Senior Loan Obligations of ETE and any Subsidiary Guarantors under the Credit Agreements and the Bank Collateral Documents. Similarly, the Notes Collateral Documents will define the terms of the security interests on the Collateral that secure the payment and performance when due of the Note Obligations of ETE and any Subsidiary Guarantors under the indenture, the notes and the Notes Collateral Documents.

Collateral Agency Agreement

The Agents will enter into the Collateral Agency Agreement with the Collateral Agent, ETE and any Subsidiary Guarantors from time to time party thereto with respect to the Collateral. The Collateral Agency Agreement will describe, among other things, the obligations, powers and duties of the Collateral Agent and the administration, preservation and disposition of the Collateral. The indenture and the Collateral Documents will be subject to the terms of the Collateral Agency Agreement.

The Collateral Agency Agreement will provide that the Collateral Agent or its sub-agent, acting at the direction of any Agents and subject to the limitations set forth in the Pledge Agreement or applicable law, will have the sole right to exercise remedies against the Collateral and to foreclose upon, collect or otherwise enforce the Liens on the Collateral for the benefit of the Secured Parties. The Collateral Agent will be instructed to comply with all instructions received by it from one or more administrative agents and, if the Collateral Agent receives conflicting instructions from two or more administrative agents, the Collateral Agent will not be required to comply with any such instructions until the Collateral Agent is reasonably satisfied that such conflict has been resolved; provided that if one instruction requires action and another inaction or a forbearance, then the Collateral Agent will be instructed to disregard the instruction requiring inaction or forbearance.

If any Collateral is sold or otherwise realized upon by the Collateral Agent in connection with any foreclosure, collection or other enforcement of the Liens granted to the Collateral Agent in the Collateral or any other exercise of remedies, the proceeds received by the Collateral Agent from such foreclosure, collection or other enforcement or realization will be distributed by the Collateral Agent as follows:

 

1.

First, to any costs, fees, charges or other amounts incurred by the Collateral Agent to collect such cash proceeds or realize upon the Collateral or otherwise owing to the Collateral Agent under the Collateral Agency Agreement or the Pledge Agreement;

 

2.

Second, to (a) the Agents in proportion to the aggregate amount of the Senior Obligations (other than the Other Hedging Obligations (as defined in the Revolving Credit Agreement)) owed to each for application in accordance with the terms of the applicable Senior Debt Documents and (b) the administrative agent under the Revolving Credit Agreement for application to the payment of that portion of the Senior Obligations constituting Other Hedging Obligations, in each case, on a pari passu basis until all such amounts are indefeasibly paid in full in cash; and

 

3.

Third, the balance, if any, after all of the Senior Obligations have been indefeasibly paid in full in cash, to ETE or as otherwise required by law.

No amendment or waiver of or consent to any departure from any provision of the Collateral Agency Agreement will be effective unless it is in writing and signed by each administrative agent under the Credit Agreements, the Collateral Agent and each Subsidiary Guarantor. In addition, any amendment, waiver or consent

 

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that either (i) adversely affects the equal and ratable treatment of the security interest of the Trustee or additional trustee (unless otherwise authorized pursuant to the terms of the Collateral Agency Agreement) or (ii) imposes new material obligations on the Trustee, in its capacity as such, shall not be effective unless it is signed by the Trustee.

Additional Senior Secured Debt

To the extent, but only to the extent, permitted by the provisions of the Senior Debt Documents, ETE may incur or issue and sell one or more Series of Additional Senior Secured Debt. Any such additional Series of Additional Senior Secured Debt may be secured by Liens on the Collateral that rank pari passu with the Liens securing the Senior Loan Obligations and may be guaranteed by the Subsidiary Guarantors, if any, on a senior basis, in each case under and pursuant to the Collateral Documents, if and subject to the condition that the Authorized Representative with respect to any such Series of Additional Senior Secured Debt, acting on behalf of the holders of such Series of Additional Senior Secured Debt, becomes a party to the Collateral Agency Agreement by satisfying the conditions set forth therein.

Release of Collateral

The Collateral Agent’s Liens upon the Collateral will automatically be released in whole, upon (a) payment in full and discharge of all outstanding Senior Obligations and (b) termination or expiration of all commitments to extend credit under all Senior Debt Documents and the cancellation or termination or cash collateralization of all outstanding letters of credit issued pursuant to any Senior Debt Document. The Collateral Agent’s Liens upon the Collateral will automatically be released with respect to any Series of Senior Obligations, including the Note Obligations, (a) at any time the terms of such Series of Senior Obligations no longer require such Series to be secured by the Collateral and (b) the administrative agent or the Trustee, as the case may be, with respect to such Series of Senior Obligations has delivered to the Collateral Agent a written notice withdrawing such Series of Senior Obligations as being secured under the Pledge Agreement. In each such case, upon request of ETE and any administrative agent or the Trustee, as applicable, the Collateral Agent will execute (with such acknowledgements and/or notarizations as are required) any such documents as provided by ETE or such administrative agent or the Trustee, as the case may be, to evidence such release.

Each Lien on Collateral securing any Note Obligation shall be released upon such Collateral becoming not subject to any Lien securing any other Series of Senior Obligations (including pursuant to any waiver or amendment of the Credit Agreements or the Bank Collateral Documents). In this regard, the release of Liens (including Liens securing Note Obligations) on Collateral would occur upon any sale, transfer or other disposition of such Collateral that is made in accordance with the terms of the Credit Agreements and the Bank Collateral Documents, so that the sale, transfer or other disposition could be made free of those Liens. For example, the Credit Agreements contain negative covenants that prohibit us from selling, transferring or disposing of any of our properties, subject to a number of exceptions, including an exception under the Term Loan Agreement that permits us to sell, transfer or dispose of any of our properties (including ETP common units but excluding our general partnership interests in ETP or our direct or indirect interests in ETP GP and ETP LLC which hold such general partnership units) subject only to (a) no event of default then existing or resulting from such sale and (b) pro forma compliance with the Leverage Ratio (as defined in the Term Loan Agreement). These negative covenants also prohibit us from declaring and making cash distributions to our unitholders so long as an event of default exists or would result from such restricted payment. Our partnership agreement requires us to make quarterly cash distributions of 100% of our available cash, which is defined in our partnership agreement to generally mean, for each calendar quarter, cash generated from our business in excess of the amount our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for the conduct of our business, or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters. As a result, we will be entitled to sell ETP common units but not general partnership interests in ETP or our direct or indirect interests in the entities that hold such general partnership units in ETP and to make quarterly distributions of our available cash without restrictions based on the Liens securing the Senior Obligations subject only to (a) no event of default and (b) in the case of asset sales, pro forma compliance with the Leverage Ratio (as defined in the Credit Agreements). In the case of Liens securing Subsidiary Guarantees, if any, the release of

 

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Liens (including Liens securing Note Obligations) on Collateral would also occur upon the owner of the Collateral ceasing to be a Subsidiary and/or a Subsidiary Guarantor, in each case, pursuant to a transaction permitted by the Collateral Agency Agreement.

Liens on Collateral securing Note Obligations will be entitled to be released in the event of the defeasance or discharge of the indenture as described under “— Defeasance and Discharge” and as described under “— Amendments and Waivers.” Each of the Notes Collateral Agent and each other Authorized Representative shall execute and deliver all such authorizations and other instruments and take such actions (and the Holders of the notes will be deemed to have consented to and authorized the Notes Collateral Agent to execute and deliver any such authorization or instrument and take any such action) as is reasonably required for the Collateral Agent to evidence, confirm and effectuate any release of Collateral described above.

At the request of ETE, the Notes Collateral Agent will execute and deliver any documents, authorizations, instructions or instruments evidencing the consent of the Holders of the notes (and the Holders of the notes will be deemed to have consented to and authorized the Notes Collateral Agent to execute and deliver any such documentation, instructions or instruments) to any permitted release. The indenture will also direct the Notes Collateral Agent, in its capacity as Authorized Representative for Holders of notes, to take any action authorized under the Notes Collateral Documents or otherwise as may be requested by ETE to give effect to any such release.

Covenants

Change of Control

If a Change of Control Triggering Event occurs, each Holder of notes will have the right to require ETE to repurchase all or any part (equal to $1,000 or an integral multiple of $1,000) of that Holder’s notes pursuant to an offer (“Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, ETE will offer a payment in cash (the “Change of Control Payment”) equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest on the notes repurchased to the date of purchase (the “Change of Control Payment Date”), subject to the rights of Holders of notes on the relevant record date to receive interest, if any, due on the relevant interest payment date. Within 30 days following any Change of Control Triggering Event, ETE will mail a notice to each Holder describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. ETE will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control Triggering Event provisions of the indenture, ETE will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control Triggering Event provisions of the indenture by virtue of such compliance.

On the Change of Control Payment Date, ETE will, to the extent lawful:

(1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(3) deliver or cause to be delivered to the Trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by ETE.

 

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The paying agent will promptly mail to each Holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each Holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a principal amount of $1,000 or an integral multiple thereof. Any note so accepted for payment will cease to accrue interest on and after the Change of Control Payment Date unless ETE defaults in making the Change of Control Payment. ETE will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date. The provisions described herein that require ETE to make a Change of Control Offer following a Change of Control Triggering Event will be applicable regardless of whether any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control Triggering Event, the indenture does not contain provisions that permit the Holders of the notes to require that ETE repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

ETE will not be required to make a Change of Control Offer upon a Change of Control Triggering Event if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by ETE and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption “— Optional Redemption,” all conditions to any such redemption shall have been satisfied or waived, unless and until there is a default in payment of the applicable redemption price. A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of such Change of Control, if a definitive agreement is in place for a Change of Control at the time of making the Change of Control Offer. Notes repurchased by ETE pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and cancelled, at ETE’s option. Notes purchased by a third party pursuant to the preceding paragraph will have the status of notes issued and outstanding.

The occurrence of certain change of control events identified in the Credit Agreements constitutes a default under the Credit Agreements. Any future Credit Facilities or other agreements relating to the Indebtedness to which ETE becomes a party may contain similar provisions. If a Change of Control Triggering Event were to occur, ETE may not have sufficient available funds to pay the Change of Control Payment for all notes that might be delivered by Holders of notes seeking to accept the Change of Control Offer after first satisfying its obligations under the Credit Agreements or other agreements relating to Indebtedness, if accelerated. The failure of ETE to make or consummate the Change of Control Offer or pay the Change of Control Payment when due will constitute a Default under the indenture and will otherwise give the Trustee and the Holders of notes the rights described under “— Events of Default and Remedies.” See “Risk Factors — Risks Relating to the Notes — We may not be able to repurchase the notes upon a change of control.”

The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of ETE and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of notes to require ETE to repurchase such Holder’s notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of ETE and its Subsidiaries taken as a whole to another Person or group may be uncertain.

Limitations on Liens

ETE will not, nor will it permit any Restricted Subsidiary to, create, assume or incur any Lien (other than any Permitted Lien) upon any Principal Property, whether owned on the Issue Date or thereafter acquired, to secure any Indebtedness of ETE or any other Person unless contemporaneously with the creation, assumption or incurrence of such Lien effective provisions are made whereby all of the outstanding notes are secured equally and ratably with, or prior to, such Indebtedness so long as such Indebtedness is so secured (except that Liens

 

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securing Subordinated Indebtedness shall be expressly subordinate to any Lien securing the notes to at least the same extent such Subordinated Indebtedness is subordinate to the notes or a Subsidiary Guarantee, as the case may be).

Notwithstanding the foregoing, ETE may, and may permit any Restricted Subsidiary to, create, assume, incur or suffer to exist any Lien upon any Principal Property to secure Indebtedness (including without limitation Senior Loan Obligations under one or more Revolving Credit Facilities); provided that the aggregate principal amount of all Indebtedness then outstanding secured by such Lien and all similar Liens under this paragraph, together with all Attributable Indebtedness from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by clauses (1) through (3), inclusive, of the first paragraph of the restriction on sale-leasebacks covenant described below), does not exceed the greater of (x) $250.0 million and (y) 10.0% of Net Tangible Assets.

Restriction on Sale-Leasebacks

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

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

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

(3) ETE or such Restricted Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the Attributable Indebtedness from such Sale-Leaseback Transaction to (a) the prepayment, repayment, redemption, reduction or retirement of any Indebtedness of ETE or any Restricted Subsidiary that is not Subordinated Indebtedness, or (b) the purchase of Principal Property used or to be used in the ordinary course of business of ETE or the Restricted Subsidiaries.

Notwithstanding the foregoing, ETE may, and may permit any Subsidiary to, effect any Sale-Leaseback Transaction that is not permitted by clauses (1) through (3), inclusive, of the preceding paragraph, provided that the Attributable Indebtedness from such Sale-Leaseback Transaction, together with the aggregate principal amount of outstanding Indebtedness secured by liens upon Principal Properties (other than Permitted Liens), does not exceed the greater of (x) $250.0 million and (y) 10.0% of Net Tangible Assets.

Limitation on Transactions with Affiliates

ETE will not, and will not cause or permit any Restricted Subsidiary to, directly or indirectly, enter into, amend or permit or suffer to exist any transaction or series of related transactions (including, without limitation, the purchase, sale, lease or exchange of any property, the guaranteeing of any Indebtedness or the rendering of any service, but excluding any cash distribution made by ETE, ETP or Regency to their respective general partners, limited partners or other equity owners in accordance with their respective partnership agreements or, in the case of any successors thereto, the respective constituent documents of any such successor entity) with, or for the benefit of, any of their respective Affiliates (each an “Affiliate Transaction”), other than any Affiliate Transaction that is on terms that either (i) are approved by the Conflicts Committee of the Board of Directors of ETE or (ii) taken as a whole, are fair and reasonable to ETE or the applicable Restricted Subsidiary or are no less favorable to ETE or the applicable Restricted Subsidiary than those that might reasonably have been obtained in

 

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a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate of ETE or such Restricted Subsidiary.

Reports

Regardless of whether required by the rules and regulations of the SEC, so long as any notes are outstanding, ETE will file with the SEC for public availability, within the time periods specified in the SEC’s rules and regulations (unless the SEC will not accept such a filing, in which case ETE will furnish to the holders of notes or cause the trustee to furnish to the holders of notes, within the time periods specified in the SEC’s rules and regulations, and will post on ETE’s website on a password-protected basis for availability solely for holders of notes):

(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if ETE were required to file such reports; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if ETE were required to file such reports.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on ETE’s consolidated financial statements by ETE’s certified independent accountants.

If, at any time, ETE is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, ETE will nevertheless continue filing the reports specified in the preceding paragraphs of this covenant with the SEC within the time periods specified above unless the SEC will not accept such a filing. ETE will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept ETE’s filings for any reason, ETE will post the reports referred to in the preceding paragraphs on its website on a password-protected basis for availability solely for holders of notes within the time periods that would apply if ETE were required to file those reports with the SEC.

Merger, Consolidation or Sale of Assets

ETE may not: (1) consolidate or merge with or into another Person (regardless of whether ETE is the surviving Person); or (2) directly or indirectly sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of ETE and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person; unless:

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

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

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

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

The successor will be substituted for ETE in the indenture with the same effect as if it had been an original party to the indenture. Thereafter, the successor may exercise the rights and powers of ETE under the indenture. If ETE conveys or transfers all or substantially all of its assets, it will be released from all liabilities and obligations under the indenture and under the notes except that no such release will occur in the case of a lease of all or substantially all of its assets. Notwithstanding the foregoing, this “Merger, Consolidation or Sale of Assets” covenant will not apply to: (1) a merger of ETE with an Affiliate solely for the purpose of organizing ETE in

 

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another jurisdiction within the United States of America; or (2) any merger or consolidation, or any sale, transfer, assignment, conveyance, lease or other disposition of assets between or among ETE and its Restricted Subsidiaries that are Subsidiary Guarantors.

Events of Default and Remedies

Each of the following is an Event of Default under the indenture with respect to the notes:

(1) default for 30 days in the payment when due of interest on the notes;

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

(3) failure by ETE to comply with any of its agreements or covenants described above under “— Covenants — Merger, Consolidation or Sale of Assets,” or in respect of its obligations to make or consummate a Change of Control Offer as described under “— Covenants — Change of Control;”

(4) failure by ETE to comply with its other covenants or agreements in the indenture applicable to the notes for 60 days after written notice of default given by the Trustee or the Holders of at least 25% in aggregate principal amount of the outstanding notes;

(5) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by ETE or any of its Subsidiaries (or the payment of which is guaranteed by ETE or any of its Subsidiaries) whether such Indebtedness or guarantee now exists, or is created after the Issue Date, if that default both (A) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”) and (B) results in the acceleration of such Indebtedness prior to its express maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $100.0 million or more;

(6) certain events of bankruptcy, insolvency or reorganization of ETE or any of its Significant Subsidiaries or any group of Subsidiaries of ETE that, taken together, would constitute a Significant Subsidiary;

(7) except as permitted by the indenture, any Subsidiary Guarantee by a Subsidiary Guarantor is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Subsidiary Guarantor, or any Person acting on behalf of any Subsidiary Guarantor, denies or disaffirms the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee; and

(8) any security interest and Lien purported to be created by any Notes Collateral Document with respect to any Collateral, individually or in the aggregate, having a Fair Market Value in excess of $100.0 million shall cease to be in full force and effect, or shall cease to give the Notes Collateral Agent, for the benefit of the Holders of the notes, the Liens, rights, powers and privileges purported to be created and granted thereby (including a perfected first-priority security interest in and Lien on, all of the Collateral thereunder (except as otherwise expressly provided in the indenture and the Notes Collateral Documents)) in favor of the Notes Collateral Agent, for a period of 30 days after notice by the Trustee or by the Holders of at least 25% of the aggregate principal amount of the notes then outstanding, or shall be asserted by ETE or any Subsidiary Guarantor to not be, a valid, perfected, first-priority (except as otherwise expressly provided in the indenture and the Notes Collateral Documents) security interest in or Lien on the Collateral covered thereby; except to the extent that any such loss of perfection or priority results from the failure of the Notes Collateral Agent or the Trustee (or an agent or trustee on its behalf) to maintain possession of certificates actually delivered to it (or such agent or trustee) representing securities pledged under the Notes Collateral Documents.

 

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An Event of Default for the notes will not necessarily constitute an Event of Default for any other series of debt securities issued under the indenture, and an Event of Default for any such other series of debt securities will not necessarily constitute an Event of Default for the notes. Further, an event of default under other indebtedness of ETE or its Subsidiaries will not necessarily constitute a Default or an Event of Default for the notes. If an Event of Default (other than an Event of Default described in clause (6) above with respect to ETE) with respect to the notes occurs and is continuing, the Trustee by notice to ETE, or the Holders of at least 25% in principal amount of the outstanding notes by notice to ETE and the Trustee, may, and the Trustee at the request of such Holders shall, declare the principal of and accrued and unpaid interest on all the notes to be due and payable. Upon such a declaration, such principal and accrued and unpaid interest will be due and payable immediately. The indenture provides that if an Event of Default described in clause (6) above occurs with respect to ETE, the principal of and accrued and unpaid interest on the notes will become and be immediately due and payable without any declaration of acceleration, notice or other act on the part of the Trustee or any Holders of notes. However, the effect of such provision may be limited by applicable law. The Holders of a majority in principal amount of the outstanding notes may, by written notice to the Trustee, rescind any acceleration with respect to the notes and annul its consequences if rescission would not conflict with any judgment or decree of a court of competent jurisdiction and all existing Events of Default with respect to the notes, other than the nonpayment of the principal of and interest on the notes that have become due solely by such acceleration, have been cured or waived.

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

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

(2) Holders of at least 25% in principal amount of the outstanding notes have requested in writing that the Trustee pursue the remedy;

(3) such Holders have offered the Trustee security or indemnity satisfactory to the Trustee in its sole discretion against any cost, liability or expense;

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

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

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

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

 

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required to deliver to the Trustee, within 30 days after the occurrence thereof, an officers’ certificate specifying any Default or Event of Default, its status and what action ETE is taking or proposes to take in respect thereof.

Authorization of Actions to Be Taken

Each Holder of notes, by its acceptance thereof, will be deemed to have consented and agreed to the terms of each Notes Collateral Document, as originally in effect and as amended, supplemented or replaced from time to time in accordance with its terms or the terms of the indenture, to have authorized and directed the Notes Collateral Agent to enter into the Notes Collateral Documents to which it is a party, and to have authorized and empowered the Notes Collateral Agent and (through the Collateral Agency Agreement) the Collateral Agent to bind the Holders of notes and other holders of Senior Obligations as set forth in the Collateral Documents to which they are a party and to perform its obligations and exercise its rights and powers thereunder, including entering into amendments permitted by the terms of the indenture or the Collateral Documents.

Amendments and Waivers

Except as otherwise provided below, amendments of the indenture, the notes or the Notes Collateral Documents may be made by ETE and the Trustee with the written consent of the Holders of a majority in principal amount of the debt securities of each affected series then outstanding under the indenture (including consents obtained in connection with a tender offer or exchange offer for notes). However, without the consent of each Holder of an affected note, no amendment may, among other things:

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

(2) reduce the rate of or change the time for payment of interest on any note;

(3) reduce the principal of or extend the stated maturity of any note;

(4) reduce the premium payable upon the redemption of any note as described above under “— Optional Redemption;” provided, however, that any purchase or repurchase of notes, including pursuant to the covenant described above under the caption “— Covenants — Change of Control;” shall not be deemed a redemption of the notes;

(5) make any notes payable in money other than U.S. dollars;

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

(7) make any change in the amendment provisions which require each Holder’s consent or in the waiver provisions.

Furthermore, without the consent of the Holders of at least two-thirds in principal amount of the notes then outstanding, an amendment or waiver may not make any change in any Notes Collateral Document or the provisions in the indenture dealing with the Collateral or the Notes Collateral Documents or the application of trust proceeds of the Collateral in any case that would release all or substantially all of the Collateral from the Liens of the Notes Collateral Documents (except as permitted by the terms of the indenture and the Notes Collateral Documents) or change or alter the priority of the security interests in the Collateral. The Holders of a majority in principal amount of the outstanding notes may waive compliance by ETE with certain restrictive covenants on behalf of all Holders of notes, including those described under “— Covenants — Limitations on Liens” and “— Covenants — Restriction on Sale-Leasebacks.” The Holders of a majority in principal amount of the outstanding notes, on behalf of all such Holders, may waive any past or existing Default or Event of Default with respect to the notes (including any such waiver obtained in connection with a tender offer or exchange offer for the notes), except a Default or Event of Default in the payment of principal, premium or interest or in respect of a provision that under the indenture cannot be modified or amended without the consent of the Holder of each

 

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outstanding note affected. A waiver by the Holders of notes of any series of compliance with a covenant, a Default or an Event of Default will not constitute a waiver of compliance with such covenant or such Default or Event of Default with respect to any other series of debt securities issued under the indenture to which such covenant, Default or Event of Default applies.

Without the consent of any Holder of notes, ETE and the Trustee may amend the indenture, the notes or the Notes Collateral Documents to:

(1) cure any ambiguity, omission, defect or inconsistency;

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

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

(4) establish any Subsidiary Guarantee or to reflect the release of any Subsidiary Guarantor from obligations in respect of its Subsidiary Guarantee, in either case, as provided in the indenture;

(5) secure the notes or any Subsidiary Guarantee;

(6) comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(7) add to the covenants of ETE or any Subsidiary Guarantor for the benefit of the Holders of notes or surrender any right or power conferred upon ETE or any Subsidiary Guarantor;

(8) add any additional Events of Default with respect to the notes;

(9) make any change that does not adversely affect the rights under the indenture of any Holder of notes;

(10) confirm and evidence the release, termination or discharge of any Lien securing the notes when such release, termination or discharge is permitted by the indenture or the Notes Collateral Documents;

(11) conform the text of the indenture or the notes to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of the indenture, the Subsidiary Guarantees or the notes, as certified by an Officers’ Certificate delivered to the Trustee;

(12) in the case of the Collateral Agency Agreement, in order to subject the security interests in the Collateral in respect of any Additional Senior Secured Debt Obligations and Senior Loan Obligations to the terms of the Collateral Agency Agreement, in each case to the extent the Incurrence of such Indebtedness, and the grant of all Liens on the Collateral held for the benefit of such Indebtedness were permitted hereunder;

(13) provide for the issuance of additional notes in accordance with the indenture;

(14) with respect to any Notes Collateral Document, to the extent such amendment is reasonably necessary to comply with the terms of the Collateral Agency Agreement;

(15) provide for a successor Trustee in accordance with the provisions of the indenture; and

(16) supplement any of the provisions of the indenture to such extent as shall be necessary to permit or facilitate the defeasance and discharge of any series of notes; provided, however, that any such action does not adversely affect the interest of the Holders of notes of such series or any other series of notes in any respect.

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

 

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Defeasance and Discharge

ETE may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Subsidiary Guarantors discharged with respect to their Subsidiary Guarantees (“legal defeasance”) except for:

(1) the rights of Holders of outstanding notes to receive payments in respect of the principal of or interest on such notes when such payments are due from the trust referred to below;

(2) ETE’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and ETE’s and the Subsidiary Guarantors’ obligations in connection therewith; and

(4) the legal defeasance provisions of the indenture.

ETE at any time may terminate its obligations under the covenants described under “— Covenants” (other than “Merger, Consolidation or Sale of Assets”) (“covenant defeasance”). ETE may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If ETE exercises its legal defeasance option, payment of the notes may not be accelerated because of an Event of Default. In the event covenant defeasance occurs in accordance with the indenture, the Events of Default described under clauses (3), (4), (5), (7) and (8) under the caption “— Events of Default and Remedies” and the Event of Default described under clause (6) under the caption “— Events of Default and Remedies” (but only with respect to Subsidiaries of ETE), in each case, will no longer constitute an Event of Default.

If ETE exercises its legal defeasance option, any security that may have been granted with respect to the notes will be released.

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

In the event of any legal defeasance, Holders of the notes would be entitled to look only to the trust fund for payment of principal of and any premium and interest on their notes until maturity. Although the amount of money and U.S. Government Obligations on deposit with the Trustee would be intended to be sufficient to pay amounts due on the notes at the time of their stated maturity, if ETE exercises its covenant defeasance option for the notes and the notes are declared due and payable because of the occurrence of an Event of Default, such amount may not be sufficient to pay amounts due on the notes at the time of the acceleration resulting from such Event of Default. ETE would remain liable for such payments, however. In addition, ETE may discharge all its obligations under the indenture with respect to the notes, other than its obligation to register the transfer of and exchange notes, provided that either:

 

•

it delivers all outstanding notes to the Trustee for cancellation; or

 

•

all such notes not so delivered for cancellation have either become due and payable or will become due and payable at their stated maturity within one year or are called for redemption or are to be called for redemption under arrangements satisfactory to the Trustee within one year, and in the case of this bullet point, it has deposited with the Trustee in trust an amount of cash sufficient to pay the entire indebtedness of such notes, including interest to the stated maturity or applicable redemption date.

 

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Book-Entry System

We have obtained the information in this section concerning The Depository Trust Company, or DTC, and its book-entry systems and procedures from DTC, but we take no responsibility for the accuracy of this information. In addition, the description in this section reflects our understanding of the rules and procedures of DTC as they are currently in effect. DTC could change its rules and procedures at any time. The notes will initially be represented by one or more fully registered global notes. Each such global note will be deposited with, or on behalf of, DTC or any successor thereto and registered in the name of Cede & Co. (DTC’s nominee). You may hold your interests in the global notes through DTC either as a participant in DTC or indirectly through organizations which are participants in DTC.

So long as DTC or its nominee is the registered owner of the global securities representing the notes, DTC or such nominee will be considered the sole owner and Holder of the notes for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in the notes will not be entitled to have the notes registered in their names, will not receive or be entitled to receive physical delivery of the notes in definitive form and will not be considered the owners or Holders of the notes under the indenture, including for purposes of receiving any reports delivered by us or the Trustee pursuant to the indenture.

Accordingly, each person owning a beneficial interest in a note must rely on the procedures of DTC or its nominee and, if such person is not a participant, on the procedures of the participant through which such person owns its interest, in order to exercise any rights of a Holder of notes.

Notes in certificated form will not be issued to beneficial owners in exchange for their beneficial interests in a global note unless (a) DTC notifies ETE that it is unwilling or unable to continue as depositary for the global notes and a successor depositary is not appointed by ETE within 90 days of such notice, (b) an Event of Default has occurred with respect to such series and is continuing and the registrar has received a request from DTC to issue notes in lieu of all or a portion of the global notes of such series, or (c) ETE determines not to have the notes represented by global notes.

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

 

•

a limited-purpose trust company organized under the New York Banking Law;

 

•

a “banking organization” under the New York Banking Law;

 

•

a member of the Federal Reserve System;

 

•

a “clearing corporation” under the New York Uniform Commercial Code; and

 

•

a “clearing agency” registered under the provisions of Section 17A of the Securities Exchange Act of 1934.

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

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

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participant. DTC agrees with and represents to DTC participants that it will administer its book-entry system in accordance with its rules and by-laws and requirements of law. The SEC has on file a set of the rules applicable to DTC and its direct participants.

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

To facilitate subsequent transfers, all notes deposited with DTC are registered in the name of DTC’s nominee, Cede & Co. The deposit of notes with DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the notes. DTC’s records reflect only the identity of the direct participants to whose accounts such notes are credited, which may or may not be the beneficial owners. The participants will remain responsible for keeping account of their holdings on behalf of their customers.

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

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

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

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

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will mail an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the notes are credited on the record date (identified in a listing attached to the omnibus proxy).

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

Concerning the Trustee

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

If an Event of Default occurs and is not cured or waived, the Trustee is required to exercise such of the rights and powers vested in it by the indenture and use the same degree of care and skill in their exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. Subject to such provisions, the Trustee will not be under any obligation to exercise any of its rights or powers under the indenture at the request of any of the Holders of notes unless they have offered to the Trustee security or indemnity satisfactory to the Trustee in its sole discretion against the costs, expenses and liabilities it may incur.

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

Non-Recourse to the General Partners; No Personal Liability of Officers, Directors, Employees or Partners

None of LE GP, LLC, our general partner, its directors, officers, employees and partners nor the limited partners of ETE will have any personal liability for our obligations under the indenture or the notes. Each Holder of notes, by accepting a note, waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the notes.

Separateness

Each Holder of notes, by accepting a note, will be deemed to have acknowledged and affirmed (i) the separateness of ETP and Regency from ETE and each Restricted Subsidiary, (ii) that it has purchased the notes from ETE in reliance upon the separateness of ETP and Regency from ETE and each Restricted Subsidiary, (iii) that ETP and Regency have assets and liabilities that are separate from those of ETE and any Restricted Subsidiary, (iv) that the Note Obligations have not been guaranteed by ETP, Regency or any of their respective subsidiaries and (v) that, except as other Persons may expressly assume or guarantee any of the Note Documents or Note Obligations, the Holders of notes shall look solely to the property and assets of ETE, and any property pledged as Collateral with respect to the Note Documents, for the repayment of any amounts payable under any Note Document or the notes and for satisfaction of the Note Obligations and that none of ETP or any of its subsidiaries shall be personally liable to the Holders of notes for any amounts payable, or any other Note Obligation, under the Note Documents.

Governing Law

The indenture, the notes and the Collateral Agency Agreement will be governed by the laws of the State of New York.

 

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Definitions

“Additional Senior Secured Debt” means any Indebtedness of ETE or any Subsidiary Guarantor (other than Indebtedness constituting Senior Loan Obligations or Indebtedness under the notes and the Subsidiary Guarantees) secured by a Lien on Collateral on a pari passu basis with the Senior Loan Obligations (but without regard to control of remedies); provided, however, that such Indebtedness is permitted to be incurred, secured and guaranteed on such basis by the Senior Debt Documents.

“Additional Senior Secured Debt Documents” means, with respect to any series, issue or class of Additional Senior Secured Debt, the promissory notes, indentures, collateral documents or other operative agreements evidencing or governing such Indebtedness, as the same may be amended, restated, supplemented or otherwise modified from time to time.

“Additional Senior Secured Debt Facility” means each indenture or other governing agreement with respect to any Additional Senior Secured Debt, as the same may be amended, restated, supplemented or otherwise modified from time to time.

“Additional Senior Secured Debt Obligations” means, with respect to any series, issue or class of Additional Senior Secured Debt, (1) all principal of and interest (including, without limitation, any interest that accrues after the commencement of any case, proceeding or other action relating to the bankruptcy, insolvency or reorganization of any Obligor, whether or not allowed or allowable as a claim in any such proceeding) payable with respect to such Additional Senior Secured Debt, (2) all other amounts payable to the related Additional Senior Secured Debt Parties under the related Additional Senior Secured Debt Documents and (3) any renewals, extensions or refinancings of the foregoing.

“Additional Senior Secured Debt Parties” means, with respect to any series, issue or class of Additional Senior Secured Debt, the holders of such Indebtedness from time to time, any trustee or agent therefor under any related Additional Senior Secured Debt Documents and the beneficiaries of each indemnification obligation undertaken by any Obligor under any related Additional Senior Secured Debt Documents, but shall not include the Obligors or any controlled Affiliates thereof (unless such Obligor or controlled Affiliate is a holder of such Indebtedness, a trustee or agent therefor or a beneficiary of such an indemnification obligation named as such in an Additional Senior Secured Debt Document).

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under direct or indirect common control with” have correlative meanings.

“Agents” means, collectively, the administrative agents under the Credit Agreements, any additional agent, the Trustee, any additional trustee, and any hedge counterparty with respect to Other Hedging Obligations that has executed a Collateral Agency Hedge Counterparty Joinder (each as defined in the Revolving Credit Agreement).

“Attributable Indebtedness,” when used with respect to any Sale-Leaseback Transaction, means, as at the time of determination, the present value (discounted at the rate set forth or implicit in the terms of the lease included in such transaction) of the total obligations of the lessee for rental payments (other than amounts required to be paid on account of property taxes, maintenance, repairs, insurance, assessments, utilities, operating and labor costs and other items that do not constitute payments for property rights) during the remaining term of the lease included in such Sale-Leaseback Transaction (including any period for which such lease has been extended). In the case of any lease that is terminable by the lessee upon the payment of a penalty or other

 

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termination payment, such amount shall be the lesser of the amount determined assuming termination upon the first date such lease may be terminated (in which case the amount shall also include the amount of the penalty or termination payment, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated) or the amount determined assuming no such termination.

“Authorized Representative” means (1) in the case of any Revolving Credit Agreement Obligations or the Revolving Credit Senior Secured Parties, the Revolving Credit Facility Collateral Agent, (2) in the case of any Term Loan Agreement Obligations or the Term Loan Senior Secured Parties, the Term Loan Facility Collateral Agent, (3) in the case of the notes or the Holders of the notes, the Notes Collateral Agent and (4) in the case of any Series of Additional Senior Secured Debt Obligations or Additional Senior Secured Debt Parties that become subject to the Collateral Agency Agreement after the date of such agreement, the Senior Representative named for such Series in the applicable Joinder Agreement, in the case of each of clauses (1), (2), (3) and (4) hereof only so long as such Senior Obligations are secured by a Lien on the Collateral under the Collateral Documents.

“Bank Collateral Documents” means, collectively, the Term Loan Facility Collateral Documents and the Revolving Credit Facility Collateral Documents.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

(3) with respect to a limited liability company, the managing member or members or any controlling committee of managers or members thereof or any board or committee serving a similar management function; and

(4) with respect to any other Person, the individual, board or committee of such Person serving a management function similar to those described in clauses (1), (2) or (3) of this definition.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, regardless of whether such debt securities include any right of participation with Capital Stock.

“Change of Control” means:

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than one or more Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 50% of the total voting power of the Voting Stock of ETE or the General Partner (or their respective successors by merger, consolidation or purchase of all or substantially all of their respective assets);

 

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(2) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of ETE and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) other than a Permitted Holder; or

(3) the adoption of a plan or proposal for the liquidation or dissolution of ETE.

“Change of Control Triggering Event” means the occurrence of both a Change of Control and a Rating Decline with respect to the notes.

“Code” means the Internal Revenue Code of 1986, as amended, together with all rules and regulations promulgated with respect thereto.

“Collateral” means any assets or property upon which there are any Liens securing Senior Loan Obligations or Additional Secured Debt Obligations (other than (i) any cash or cash equivalents collateralizing letter of credit obligations under the Credit Facilities and or (ii) proceeds of an event requiring a mandatory prepayment under any of the Credit Agreements).

“Collateral Agency Agreement” means the amended and restated collateral agency agreement dated on or about the Issue Date among the administrative agent under the Term Loan Facility, the administrative agent under the Revolving Credit Facility, the Trustee, the Collateral Agent, ETE and the Subsidiary Guarantors party thereto, as it may be amended from time to time.

“Collateral Agent” means, with respect to any Collateral, U.S. Bank National Association in its capacity as the “Collateral Agent” under the Collateral Agency Agreement, and any successor thereto in such capacity.

“Collateral Documents” means, collectively, the Notes Collateral Documents, the Bank Collateral Documents and each of the security agreements and other instruments executed and delivered by any Obligor pursuant to either of the Credit Agreements, the indenture or any Additional Senior Secured Debt Facility for purposes of providing collateral security for any Senior Obligation (including, in each case, any schedules, exhibits or annexes thereto), as the same may be amended, restated, supplemented or otherwise modified from time to time.

“Credit Agreements” means, collectively, the Term Loan Agreement and the Revolving Credit Agreement.

“Credit Facilities” means one or more debt facilities of ETE or any Restricted Subsidiary (which may be outstanding at the same time and including, without limitation, the Credit Agreements) with banks or other institutional lenders or investors or indentures providing for revolving credit loans, term loans, letters of credit or other long-term indebtedness, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as such agreements may be amended, refinanced or otherwise restructured, in whole or in part from time to time (including increasing the amount of available borrowings thereunder or adding Subsidiaries of ETE as additional borrowers or guarantors thereunder) with respect to all or any portion of the Indebtedness under such agreement or agreements, any successor or replacement agreement or agreements or any indenture or successor or replacement indenture and whether by the same or any other agent, lender, group of lenders or investors.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“ETE Common Holdings” means ETE Common Holdings, LLC, a Delaware limited liability company, and its successors.

 

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“ETE Common Holdings Member” means ETE Common Holdings Member, LLC, a Delaware limited liability company, and its successors.

“ETE GP Acquirer” means ETE GP Acquirer LLC, a Delaware limited liability company, and its successors.

“ETP” means Energy Transfer Partners, L.P., a Delaware limited partnership, and its successors.

“ETP GP” means Energy Transfer Partners GP, L.P., a Delaware limited partnership, and its successors.

“ETP LLC” means Energy Transfer Partners L.L.C., a Delaware limited liability company, and its successors.

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

“Existing Indenture” means the indenture dated as of September 20, 2010 , as supplemented by a supplemental indenture establishing the Existing Notes dated as of September 20, 2010, a second supplemental indenture dated as of February 16, 2012 and a third supplemental indenture dated as of April 24, 2012 between ETE and the Trustee.

“Existing Note Documents” means the Existing Indenture, the Existing Notes and the Notes Collateral Documents.

“Existing Note Obligations” means all Obligations of ETE and the Subsidiary Guarantors under the Existing Note Documents.

“Excluded Entity” has the meaning given to such term in the definition of “Restricted Subsidiary.”

“Fair Market Value” means, with respect to any asset, the price (after taking into account any liabilities relating to such assets) that would be negotiated in an arm’s-length transaction for cash between a willing seller and a willing and able buyer, neither of which is under any compulsion to complete the transaction.

“GAAP” means generally accepted accounting principles in the United States, applied on a consistent basis and set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants, the opinions and pronouncements of the Public Company Accounting Oversight Board and in the statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“General Partner” means LE GP, LLC, a Delaware limited partnership, and its successors as general partner of ETE.

“Hedging Contract” means (1) any agreement providing for options, swaps, floors, caps, collars, forward sales or forward purchases involving interest rates, commodities or commodity prices, equities, currencies, bonds, or indexes based on any of the foregoing, (2) any option, futures or forward contract traded on an exchange, and (3) any other derivative agreement or other similar agreement or arrangement.

“Hedging Obligations” of any Person means the obligations of such Person under any Hedging Contract.

“Indebtedness” means, with respect to any Person, any obligation created or assumed by such Person for the repayment of borrowed money or any guarantee thereof, if and to the extent such obligation would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP.

 

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“Investment Grade Rating” means a rating equal to or higher than:

(1) Baa3 (or the equivalent) by Moody’s; or

(2) BBB- (or the equivalent) by S&P, or, if either such entity ceases to rate the notes for reasons outside of ETE’s control, the equivalent investment grade credit rating from any other Rating Agency.

“Issue Date” means the first date on which notes are issued under the indenture.

“Joinder Agreement” means the documents required to be delivered by a Senior Representative to the parties to the Collateral Agency Agreement in order to establish a Series of Additional Senior Secured Debt and Additional Senior Secured Debt Parties under Collateral Agency Agreement.

“Legal Holiday” means a Saturday, a Sunday or a day on which banking institutions in the City of New York or at a place of payment are authorized by law, regulation or executive order to remain closed.

“Lien” means, with respect to any asset, any mortgage, deed of trust, lien, pledge, hypothecation, charge, security interest or similar encumbrance in, on, or of such asset, regardless of whether filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.

“MLP” means each of (a) ETP, (b) Regency, (c) Sunoco Logistics Partners L.P. or (d) any other publicly traded limited partnership or limited liability company meeting the gross income requirements of Section 7704(c)(2) of the Code created or acquired by ETE or any Restricted Subsidiary after the Issue Date, as applicable.

“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.

“Net Tangible Assets” means, at any date of determination, the total amount of assets of ETE and its Restricted Subsidiaries (including, without limitation, any assets consisting of equity securities or equity interests in any other entity) after deducting therefrom:

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

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

all as prepared in accordance with GAAP and set forth, or on a pro forma basis would be set forth, on a consolidated balance sheet of ETE and its Restricted Subsidiaries (without inclusion of assets or liabilities of any Subsidiaries that are not Restricted Subsidiaries or assets or liabilities of any equity investee) for ETE’s most recently completed fiscal quarter for which financial statements are available.

“Non-Recourse Indebtedness” means Indebtedness as to which neither ETE nor any of its Restricted Subsidiaries nor any Excluded Entity is directly or indirectly liable (as a guarantor or otherwise), other than pledges of the equity of any Person that is not a Restricted Subsidiary to secure such Non-Recourse Indebtedness of such Person.

“Note Documents” means the indenture, the notes and the Notes Collateral Documents.

“Note Obligations” means all Obligations of ETE and the Subsidiary Guarantors under the Note Documents.

 

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“notes” means the notes issued under the indenture on the Issue Date and any additional notes issued under the indenture after the Issue Date in accordance with the terms of the indenture.

“Notes Collateral Agent” means the Trustee, in its capacity as “Collateral Agent” under the indenture and under the Notes Collateral Documents, and any successor thereto in such capacity.

“Notes Collateral Documents” means the Pledge Agreement, the Collateral Agency Agreement and each other security document or pledge agreement executed by ETE or any Subsidiary Guarantor and delivered in accordance with applicable local or foreign law to grant to the Notes Collateral Agent or perfect a valid, perfected security interest in the Collateral, in each case, as amended, restated, supplemented or otherwise modified from time to time.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, costs, expenses, damages and other liabilities payable under the documentation governing any Indebtedness.

“Obligors” means ETE and each Subsidiary Guarantor, if any, and any other Person who is liable for any of the Senior Obligations.

“Permitted Holders” means (a) any of Kelcy L. Warren, Ray C. Davis, John W. McReynolds, the heirs at law of such individuals, entities or trusts owned by or established for the benefit of such individuals or their respective heirs at law (such as entities or trusts established for estate planning purposes), (b) ETP or any other Person under the management or control of ETP or (c) the General Partner and entities owned solely by existing and former management employees of the General Partner.

“Permitted Liens” means at any time:

(1) any Lien existing on any property prior to the acquisition thereof by ETE or any Restricted Subsidiary or existing on any property of any Person that becomes a Restricted Subsidiary after the Issue Date prior to the time such Person becomes a Restricted Subsidiary; provided that (i) such Lien is not created in contemplation of or in connection with such acquisition or such Person becoming a Restricted Subsidiary, as the case may be, (ii) such Lien shall not apply to any other property of ETE or any Restricted Subsidiary and (iii) such Lien shall secure only those obligations that it secures on the date of such acquisition or the date such Person becomes a Restricted Subsidiary, as the case may be;

(2) any Lien on any real or personal tangible property securing Purchase Money Indebtedness incurred by ETE or any Restricted Subsidiary;

(3) any Lien securing Indebtedness incurred in connection with extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refunding or replacements), in whole or in part, of Indebtedness secured by Liens referred to in clauses (1) or (2) above; provided, however, that any such extension, renewal, refinancing, refunding or replacement Lien shall be limited to the property or assets (including replacements or proceeds thereof) covered by the Lien extended, renewed, refinanced, refunded or replaced and that the Indebtedness secured by any such extension, renewal, refinancing, refunding or replacement Lien shall be in an amount not greater than the amount of the obligations secured by the Lien extended, renewed, refinanced, refunded or replaced and any expenses of ETE or its Subsidiaries (including any premium) incurred in connection with such extension, renewal, refinancing, refunding or replacement;

(4) any Lien on Capital Stock of a Project Finance Subsidiary securing Non-Recourse Indebtedness of such Project Finance Subsidiary and on Capital Stock of any Person that is not a Restricted Subsidiary securing Non-Recourse Indebtedness of such Person; and

(5) any Lien resulting from the deposit of moneys or evidence of indebtedness in trust for the purpose of defeasing Indebtedness of ETE or any Restricted Subsidiary.

 

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

“Pledge Agreement” means the Second Amended and Restated Pledge and Security Agreement dated on or about the Issue Date between the Subsidiary Guarantors party thereto and U.S. Bank National Association, as collateral agent for the Secured Parties, as amended, modified or supplemented from time to time.

“Possessory Collateral” means (a) any Collateral in the possession of the Collateral Agent (or its agents or bailees), to the extent that possession thereof perfects a Lien thereon under the Uniform Commercial Code of any applicable jurisdiction, (b) any rights to receive payments under any insurance policy that constitute Collateral and with respect to which the Collateral Agent (or any of its agents) is named as a loss payee and/or (c) any other Collateral (such as motor vehicles) with respect to which a secured party must be listed on a certificate of title in order to perfect a Lien thereon.

“Principal Property” means (a) any real property, manufacturing plant, terminal, warehouse, office building or other physical facility, and any fixtures, furniture, equipment or other depreciable assets owned or leased by ETE or any Restricted Subsidiary and (b) any Capital Stock or Indebtedness of ETP or Regency or any other Subsidiary of ETE or any other property or right, in each case, owned by or granted to ETE or any Restricted Subsidiary and used or held for use in any of the principal businesses conducted by ETE or any Restricted Subsidiaries; provided, however, that “Principal Property” shall not include any property or right that, in the opinion of the Board of Directors of ETE as set forth in a board resolution adopted in good faith, is immaterial to the total business conducted by ETE and the Restricted Subsidiaries considered as one enterprise.

“Project Finance Subsidiary” means any special purpose Subsidiary of ETE that (a) ETE designates as a “Project Finance Subsidiary” by written notice to the Trustee and is formed for the sole purpose of (x) developing, financing and operating the infrastructure and capital projects of such Subsidiary or (y) owning or financing any such Subsidiary described in clause (x), (b) has no Indebtedness other than Non-Recourse Indebtedness, (c) is a Person with respect to which neither ETE nor any of its Restricted Subsidiaries nor any Excluded Entity has any direct or indirect obligation to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and (d) has not guaranteed or otherwise directly provided credit support for any Indebtedness of ETE or any of its Restricted Subsidiaries or any Excluded Entity.

“Purchase Money Indebtedness” of any Person means any Indebtedness of such Person to any seller or other Person, that is incurred to finance the acquisition, construction, installation or improvement of any real or personal tangible property (including Capital Stock but only to the extent of the tangible assets in such Subsidiary being acquired) used or useful in the business of such Person and its Restricted Subsidiaries and that is incurred concurrently with, or within one year following, such acquisition, construction, installation or improvement.

“Rating Agency” means each of S&P and Moody’s, or if S&P or Moody’s or both shall refuse to make a rating on the notes publicly available (for any reason other than the failure by ETE to pay the customary fees of such agency), any nationally recognized statistical rating agency or agencies, as the case may be, selected by ETE, which shall be substituted for S&P or Moody’s, or both, as the case may be.

“Rating Decline” means, with respect to any Change of Control, the occurrence of:

(1) a decrease of one or more gradations (including gradations within rating categories as well as between rating categories) in the rating of the notes by both Rating Agencies; provided that the notes did not have an Investment Grade Rating from two Rating Agencies immediately before such decrease, or

(2) a decrease in the rating of the notes by both Rating Agencies, such that the notes do not have an Investment Grade Rating from two Rating Agencies immediately after such decrease;

 

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provided, however, that in each case such decrease occurs on, or within 60 days after the earlier of (a) such Change of Control, (b) the date of public notice of the occurrence of such Change of Control or (c) public notice of the intention by ETE to effect such Change of Control (which period shall be extended so long as the rating of the notes is under publicly announced consideration for downgrade by either Rating Agency); and provided, further, that a Rating Decline otherwise arising by virtue of a particular reduction in rating will not be deemed to have occurred in respect of a particular Change of Control (and thus will disregarded in determining whether a Rating Decline has occurred for purposes of the definition of Change of Control Triggering Event) if the Rating Agencies making the reduction in rating do not announce or publicly confirm or inform the Trustee in writing at ETE’s or the Trustee’s request that the reduction was the result, in whole or in part, of any event or circumstance comprised of or arising as a result of, or in respect of, the applicable Change of Control (whether or not the applicable Change of Control has occurred at the time of the Rating Decline).

“Regency” means Regency Energy Partners LP, a Delaware limited partnership, and its successors.

“Regency GP” means Regency GP LP, a Delaware limited partnership, and its successors.

“Regency LLC” means Regency GP LLC, a Delaware limited liability company, and its successors.

“Restricted Subsidiary” means any Subsidiary of ETE (other than (a) any Project Finance Subsidiary and any direct or indirect parent of any such entity that is a MLP, (b) Regency and its Subsidiaries, (c) ETP and its Subsidiaries, (d) SUG Holdco and its Subsidiaries, (e) any entity designated as an Unrestricted Person pursuant to the Revolving Credit Agreement or the Term Loan Agreement and (f) any entity that would be deemed to be a Subsidiary of any combination of the entities in clauses (a) through (e) if such entities were being treated as a single Person (with each such deemed Subsidiary, Regency, ETP, SUG and SUG Holdco being referred to individually as an “Excluded Entity”)) that owns or leases, directly or indirectly through ownership in another Subsidiary, any Principal Property.

“Revolving Credit Agreement” means the Credit Agreement dated on or about the Issue Date, among ETE, Credit Suisse AG, as administrative agent, and the lenders party thereto, as amended, restated, supplemented or otherwise modified from time to time (including with the same or different lenders).

“Revolving Credit Agreement Obligations” means all Obligations of the Obligors under the Revolving Credit Agreement, including (a) (i) obligations of ETE and the Subsidiary Guarantors from time to time arising under or in respect of the due and punctual payment of (x) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding) on the loans made under the Revolving Credit Agreement, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, (y) each payment required to be made by ETE and the Subsidiary Guarantors under the Revolving Credit Facility in respect of any letter of credit issued under the Revolving Credit Agreement, when and as due, including payments in respect of reimbursement obligations, interest thereon and obligations to provide cash collateral and (z) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of ETE and the Subsidiary Guarantors under the Revolving Credit Agreement, and (ii) the due and punctual performance of all covenants, agreements, obligations and liabilities of ETE and the Subsidiary Guarantors or pursuant to the Revolving Credit Agreement and (b) the due and punctual payment and performance of all obligations of ETE and the Subsidiary Guarantors under each Hedging Contract entered into with any counterparty that is a Senior Loan Party pursuant to the Revolving Credit Agreement.

“Revolving Credit Facility” means any revolving credit facility provided pursuant to a Revolving Credit Agreement.

 

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“Revolving Credit Facility Collateral Agent” means the administrative agent under the Revolving Credit Facility and its successors and permitted assigns that assume the role of collateral agent under the Revolving Credit Facility.

“Revolving Credit Facility Collateral Documents” means the Pledge Agreement, the Collateral Agency Agreement and each other security document or pledge agreement executed by ETE or any Restricted Subsidiary and delivered in accordance with applicable local or foreign law to grant to the Revolving Credit Facility Collateral Agent or perfect a valid, perfected security interest in the Collateral, in each case, as amended, restated, supplemented or otherwise modified from time to time.

“Revolving Credit Senior Secured Parties” means, collectively, (a) the administrative agent, each other agent, the lenders and the issuing bank, in each case, under the Revolving Credit Agreement, (b) each counterparty to a Hedging Contract if at the date of entering into such Hedging Contract such Person was an agent or a lender under the Revolving Credit Agreement or an Affiliate of an agent or a lender under the Revolving Credit Agreement and (c) the successors and permitted assigns of each of the foregoing.

“Revolving Credit Obligation Payment Date” means the date on which (a) the Revolving Credit Agreement Obligations have been paid in full, (b) all lending commitments under the Revolving Credit Agreement have been terminated and (c) there are no outstanding letters of credit issued under the Revolving Credit Agreement other than such as have been fully cash collateralized under documents and arrangements satisfactory to the issuer of such letters of credit.

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.

“SEC” means the United States Securities and Exchange Commission and any successor agency thereto.

“Secured Parties” means, with respect to any Collateral, the Senior Secured Parties whose Senior Representative is the Collateral Agent for such Collateral.

“Senior Debt Documents” means (1) the Credit Agreements and the Bank Collateral Documents, (2) the Note Documents and (3) any other Additional Senior Secured Debt Documents.

“Senior Lender” means a “Lender” as defined in either of the Credit Agreements.

“Senior Loan Obligations” means, collectively, (a) all Term Loan Agreement Obligations and (b) all Revolving Credit Agreement Obligations.

“Senior Loan Parties” means, collectively, (a) the administrative agent, the collateral agent, each other agent, the lenders and the issuing bank, in each case, under any of the Credit Agreements, (b) each counterparty to a Hedging Contract if at the date of entering into such Hedging Contract such Person was an agent or a lender under any of the Credit Agreements or an Affiliate of an agent or a lender under any of the Credit Agreements and (c) the successors and permitted assigns of each of the foregoing.

“Senior Notes Parties” means, collectively, (a) the Trustee, the Notes Collateral Agent, each other agent, the Holders of the notes, in each case, under the indenture, and (b) any other Secured Party (as defined in any Notes Collateral Document), and the successors and permitted assigns of each of the foregoing.

“Senior Obligations” means the Senior Loan Obligations, the Existing Note Obligations, the Note Obligations and any Additional Senior Secured Debt Obligations.

“Senior Representative” means, (i) in respect of a Credit Facility, the trustee, administrative agent, collateral agent, security agent or similar agent under such Credit Facility or each of their successors in such

 

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capacity, as the case may be, which Person shall also be the Authorized Representative for such Credit Facility, (ii) in respect of the indenture, the Notes Collateral Agent and (iii) in respect of any Additional Senior Secured Debt, the trustee, administrative agent, collateral agent or similar agent under any related Additional Senior Secured Debt Documents or each of their successors in such capacity, as the case may be.

“Senior Secured Parties” means the Senior Loan Parties, the Notes Secured Parties and any Additional Senior Secured Debt Parties.

“Series” means (a) the Term Loan Agreement Obligations, (b) the Revolving Credit Agreement Obligations, (c) the Existing Note Obligations, (d) the Note Obligations and (e) the Additional Senior Secured Debt Obligations incurred pursuant to any Additional Senior Secured Debt Facility, which, pursuant to any Joinder Agreement, are to be represented hereunder by a common Authorized Representative (in its capacity as such for such Additional Senior Secured Debt Obligations).

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.

“Subordinated Indebtedness” means Indebtedness of ETE or a Subsidiary Guarantor that is contractually subordinated in right of payment, in any respect (by its terms or the terms of any document or instrument relating thereto), to the notes or the Subsidiary Guarantee of such Subsidiary Guarantor, as applicable.

“Subsidiary” means, with respect to any Person:

(1) any corporation, association or other business entity of which more than 50% of the total voting power of the Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement that effectively transfers voting power) to vote in the election of directors, managers or Trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Subsidiary Guarantee” means each guarantee of the obligations of ETE under the indenture and the notes by a Subsidiary of ETE in accordance with the provisions of the indenture.

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

“SUG” means Southern Union Company, a Delaware corporation, and its successors.

“SUG Holdco” means ETE Sigma Holdco Corporation, a Delaware corporation, and its successors, which is the parent entity of SUG.

“Term Loan Agreement” means the Senior Secured Term Loan Agreement dated on or about the Issue Date, among ETE, Credit Suisse AG, as administrative agent, and the lenders party thereto, governing the term loans provided by such lenders to ETE, including any loan documents, notes, guarantees, collateral and security documents, instruments and agreements executed in connection therewith (including Hedging Obligations related to the Indebtedness incurred thereunder), and in each case as amended, restated, supplemented or otherwise modified from time to time (including with the same or different lenders or investors).

 

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“Term Loan Agreement Obligations” means all Obligations of the Obligors under the Term Loan Agreement, including (a) (i) obligations of ETE and the Subsidiary Guarantors from time to time arising under or in respect of the due and punctual payment of (x) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding) on the loans made under the Term Loan Agreement, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, and (y) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of ETE and the Subsidiary Guarantors under the Term Loan Agreement, and (ii) the due and punctual performance of all covenants, agreements, obligations and liabilities of ETE and its Restricted Subsidiaries or pursuant to the Term Loan Agreement and (b) the due and punctual payment and performance of all obligations of ETE and the Subsidiary Guarantors under each Hedging Contract entered into with any counterparty that is a Senior Loan Party pursuant to the Term Loan Agreement.

“Term Loan Facility” means any term loan facility provided pursuant to a Term Loan Agreement.

“Term Loan Facility Collateral Agent” means the administrative agent under the Term Loan Facility and its successors and permitted assigns that assume the role of collateral agent under the Term Loan Facility.

“Term Loan Facility Collateral Documents” means the Pledge Agreement and each other security document or pledge agreement executed by ETE or any Restricted Subsidiary and delivered in accordance with applicable local or foreign law to grant to the Term Loan Facility Collateral Agent or perfect a valid, perfected security interest in Collateral, in each case, as amended, restated, supplemented or otherwise modified from time to time.

“Term Loan Senior Secured Parties” means, collectively, (1) the administrative agent, each other agent and the lenders, in each case, under the Term Loan Agreement, (2) each counterparty to a Hedging Contract if at the date of entering into such Hedging Contract such Person was an agent or a lender under the Term Loan Agreement or an Affiliate of an agent or a lender under the Term Loan Agreement, and (3) the successors and permitted assigns of each of the foregoing.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

 

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

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

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

 

•

dealers in securities or currencies;

 

•

traders in securities, commodities or currencies;

 

•

U.S. holders (as defined below) whose functional currency is not the U.S. dollar;

 

•

persons holding notes as part of a hedge, straddle, conversion or other risk reduction transaction;

 

•

U.S. expatriates and certain former citizens or long-term residents of the United States;

 

•

banks, insurance companies and other financial institutions;

 

•

regulated investment companies and real estate investment trusts;

 

•

persons subject to the alternative minimum tax;

 

•

tax-exempt organizations;

 

•

“controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

 

•

partnerships, S corporations or other pass-through entities; and

 

•

persons deemed to sell the notes under the constructive sale provisions of the Code.

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

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

 

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Consequences to U.S. Holders

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

 

•

an individual who is a citizen or resident of the United States;

 

•

a corporation (or other entity that is taxable as a corporation) created or organized in or under the laws of the United States, any state thereof, or the District of Columbia;

 

•

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

 

•

a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more United States persons (within the meaning of Section 7701(a)(30) of the Code, or (2) has a valid election in effect under applicable Treasury Regulations to be treated as a United States person.

Payments of Interest

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

Sale, Exchange or Disposition of Notes

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

 

•

the amount realized upon the disposition of the note (less any amount attributable to accrued interest, which will be taxable as interest to the extent not already included in income); and

 

•

your adjusted tax basis in the note.

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

Information Reporting and Backup Withholding

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

 

•

fail to furnish a taxpayer identification number (“TIN”), which, for an individual, is ordinarily his or her social security number;

 

•

furnish an incorrect TIN;

 

•

are notified by the IRS that you have failed properly to report payments of interest or dividends; or

 

•

fail to certify, under penalties of perjury, that you have furnished a correct TIN and that the IRS has not notified you that you are subject to backup withholding.

U.S. holders should consult their tax advisors regarding their qualification for an exemption from backup withholding and the procedures for obtaining such an exemption, if applicable. Backup withholding is not an additional tax, and you may use amounts withheld as a credit against your U.S. federal income tax liability, if any, or you may claim a refund if you timely provide certain information to the IRS.

 

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Consequences to Non-U.S. Holders

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

Payments of Interest

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

 

•

you do not directly, indirectly, or constructively, own 10% or more of our capital or profits interests;

 

•

you are not a “controlled foreign corporation” that is related to us through actual or constructive capital or profits interest ownership and you are not a bank that received such note on an extension of credit made pursuant to a loan agreement entered into in the ordinary course of your trade or business; and

 

•

either (1) you certify in a statement provided to the applicable withholding agent, under penalties of perjury, that you are not a “United States person” within the meaning of the Code and provide your name and address, (2) a securities clearing organization, bank or other financial institution that holds customers’ securities in the ordinary course of its trade or business and holds the note on your behalf certifies to the applicable withholding agent under penalties of perjury that it, or the financial institution between it and you, has received from you a statement, under penalties of perjury, that you are not a United States person and provides the applicable withholding agent with a copy of such statement, or (3) you hold your note directly through a “qualified intermediary” and certain conditions are satisfied.

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

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

Sale, Exchange, or Disposition of Notes

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

 

•

the gain is effectively connected with your conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is also attributable to your permanent establishment in the United States); or

 

•

you are an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met.

 

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

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

Information Reporting and Backup Withholding

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

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

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

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus supplement, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc. are acting as representatives, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the principal amount of notes indicated in the following table.

 

Underwriter		Principal Amount of Notes
Credit Suisse Securities (USA) LLC		$
Deutsche Bank Securities Inc.
Citigroup Global Markets Inc.
Goldman, Sachs & Co.
Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith                        Incorporated
Mitsubishi UFJ Securities (USA), Inc.
Mizuho Securities USA Inc.
Morgan Stanley & Co. LLC
RBC Capital Markets, LLC
RBS Securities Inc.
UBS Securities LLC
Total		$	400,000,000

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the notes if any are purchased. The underwriting agreement also provides that, if an underwriter defaults on its purchase commitment, the purchase commitments of non-defaulting underwriters may be increased or, under certain circumstances, the underwriting agreement may be terminated.

Notes sold by the underwriters to the public will initially be offered at the public offering price set forth on the cover page of this prospectus supplement and to certain dealers at such price less a concession not in excess of     % of the principal amount of the notes and     % of the principal amount of the notes. After the initial offering of the notes to the public, the underwriters may change the offering price and other selling terms.

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

The notes are new issues of securities for which there currently is no established trading market, and the notes will not be listed on any national securities exchange. The underwriters have advised us that they intend to make a market in the notes as permitted by applicable law. They are not obligated, however, to make a market in the notes and any market-making activities may be discontinued at any time at their sole discretion and without notice. Accordingly, no assurance can be given as to the development or liquidity of any market for the notes.

In connection with the offering, the underwriters may purchase and sell notes in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of notes than it is required to purchase in the offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market prices of the notes while the offering is in progress. These activities by the underwriters may stabilize, maintain or otherwise affect the market prices of the notes. As a result, the prices of

 

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the notes may be higher than the prices that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. These transactions may be effected in the over-the-counter market or otherwise.

We estimate that the total expenses of this offering to be paid by us, excluding the underwriting discount, will be approximately $500,000.

In the ordinary course of its business, the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking or other commercial transactions with us and our affiliates for which they received or will receive customary fees and expenses. In particular, affiliates of the underwriters serve various roles under our credit facilities. Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC, RBS Securities Inc., The Bank of Tokyo—Mitsubishi UFJ, Ltd. and Mizuho Securities USA Inc. are acting joint lead arrangers and Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC, RBS Securities Inc. and The Bank of Tokyo—Mitsubishi UFJ, Ltd. are acting as joint book runners for our new revolving credit facility. Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Goldman Sachs Bank USA, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Bank PLC, The Bank of Tokyo—Mitsubishi UFJ, Ltd., Morgan Stanley Senior Funding, Inc., Mizuho Securities USA Inc., RBS Securities Inc. and RBC Capital Markets, LLC are acting co-lead arrangers and joint book runners for our new term loan facility. Credit Suisse Securities (USA) LLC is an affiliate of the administrative agent under our new credit facilities. Additionally, the underwriters or their affiliates are lenders and agents under certain of our and our subsidiaries’ credit facilities for which they receive interest and fees as provided in the credit agreements related to these facilities. Credit Suisse Securities (USA) LLC and Goldman, Sachs & Co. Inc. are also acting as dealer managers for the Tender Offer. Several of the underwriters may participate and tender notes owned by such institutions in the Tender Offer and thereby receive a portion of the proceeds of this offering.

Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities, including potentially the notes offered hereby. Any such short positions could adversely affect future trading prices of the notes offered hereby.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our or our subsidiaries’ securities and instruments.

Notice to Prospective Investors in the European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a Relevant Member State), each Underwriter represents and agrees that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the Relevant Implementation Date) it has not made and will not make an offer of Securities to the public in that Relevant Member State prior to the publication of a prospectus in relation to the Securities which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of Securities to the public in that Relevant Member State at any time,

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

 

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(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the manager for any such offer; or

(d) in any other circumstances which do not require the publication by the Issuer of a prospectus pursuant to Article 3 of the Prospectus Directive.

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

Notice to Prospective Investors in the United Kingdom

Each of the underwriters severally represents, warrants and agrees as follows:

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling with Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to the company; and

(b) it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the Class A Common Stock in, from or otherwise involving the United Kingdom.

 

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LEGAL MATTERS

The validity of the notes in this offering will be passed upon for us by Latham & Watkins LLP, Houston, Texas. The validity of the notes will be passed upon for the underwriters by Simpson Thacher & Bartlett LLP, New  York, New York.

EXPERTS

The consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus supplement and elsewhere in the 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.

The consolidated financial statements of Energy Transfer Partners, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus supplement and elsewhere in the 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.

The consolidated financial statements of Energy Transfer Partners GP, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, included in this prospectus supplement and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Regency Energy Partners LP and subsidiaries as of December 31, 2012 and 2011 and for the years then ended, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus supplement and elsewhere in the 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.

The consolidated financial statements of RIGS Haynesville Partnership Co. and subsidiaries as of December 31, 2012 and 2011 and for the years then ended incorporated by reference in this prospectus supplement and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Lone Star NGL LLC and subsidiaries as of December 31, 2012 and 2011 and for the year ended December 31, 2012 and for the period from inception (March 21, 2011) to December 31, 2011 incorporated by reference in this prospectus supplement and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Southern Union Gathering Company, LLC and subsidiaries as of December 31, 2012 and for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012 incorporated by reference in this prospectus supplement and elsewhere in the registration statement have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

 

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The consolidated financial statements of Regency Energy Partners LP for the period from May 26, 2010 to December 31, 2010 and the period from January 1, 2010 to May 25, 2010 have been incorporated by reference herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

The financial statements of RIGS Haynesville Partnership Co. as of and for the year ended December 31, 2010 included in Exhibit 99.3 of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of KPMG LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Midcontinent Express Pipeline LLC as of and for the years ended December 31, 2012 and 2011 and as of December 31, 2011 and 2010 and for the year ended December 31, 2011 and for the seven-month period ended December 31, 2010, included in Exhibits 99.4 and 99.5, respectively, of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of LDH Energy Asset Holdings LLC as of December 31, 2010 and 2009 and for the three year period ended December 31, 2010 included in Exhibit 99.7 of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of Ernst & Young LLP, independent auditors, given on the authority of said firm as experts in auditing and accounting.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

 

Consolidated Balance Sheets—September 30, 2013 and December 31, 2012			F-4
Consolidated Statements of Operations—Three and Nine Months Ended September 30, 2013 and 2012			F-6
Consolidated Statements of Comprehensive Income (Loss)—Three and Nine Months Ended September  30, 2013 and 2012			F-7
Consolidated Statement of Equity—Nine Months Ended September 30, 2013			F-8
Consolidated Statements of Cash Flows—Nine Months Ended September 30, 2013 and 2012			F-9
Notes to Consolidated Financial Statements			F-10

 

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Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

 

/d		per day
AmeriGas		AmeriGas Partners, L.P.
AOCI		accumulated other comprehensive income (loss)
Bbls		barrels
Btu		British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Canyon		ETC Canyon Pipeline, LLC
Citrus		Citrus Corp., which owns 100% of FGT
ETC FEP		ETC Fayetteville Express Pipeline, LLC
ETC OLP		La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
ETC Tiger		ETC Tiger Pipeline, LLC
ETP		Energy Transfer Partners, L.P.
ETP Credit Facility		ETP’s $2.5 billion revolving credit facility
ETP GP		Energy Transfer Partners GP, L.P., the general partner of ETP
ETP LLC		Energy Transfer Partners, L.L.C., the general partner of ETP GP
EPA		U.S. Environmental Protection Agency
Exchange Act		Securities Exchange Act of 1934
FEP		Fayetteville Express Pipeline LLC
FERC		Federal Energy Regulatory Commission
FGT		Florida Gas Transmission Company, LLC
GAAP		accounting principles generally accepted in the United States of America
HPC		RIGS Haynesville Partnership Co.
Holdco		ETP Holdco Corporation
Holdco Acquisition		ETP’s April 30, 2013 acquisition of ETE’s 60% interest in Holdco
Holdco Transaction		October 5, 2012 transaction including contributions from ETP and ETE to Holdco
IDRs		incentive distribution rights
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas
Lone Star		Lone Star NGL LLC
MGE		Missouri Gas Energy
MEP		Midcontinent Express Pipeline LLC
MMBtu		million British thermal units
MTBE		methyl tertiary butyl ether
NEG		New England Gas Company
NGL		natural gas liquid, such as propane, butane and natural gasoline
NYMEX		New York Mercantile Exchange
OSHA		Federal Occupational Safety and Health Act
OTC		over-the-counter
Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBs		polychlorinated biphenyl
PEPL		Panhandle Eastern Pipe Line Company, LP
PEPL Holdings		PEPL Holdings, LLC, a wholly-owned subsidiary of Southern Union, which owns the general partner and 100% of the limited partner interests in Panhandle Eastern Pipeline Company, LP
PES		Philadelphia Energy Solutions
PHMSA		Pipeline Hazardous Materials Safety Administration

 

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Preferred Units		ETE’s Series A Convertible Preferred Units
Propane Business		Heritage Operating, L.P. and Titan Energy Partners, L.P.
Propane Contribution		ETP’s contribution of its Propane Business to AmeriGas
Regency		Regency Energy Partners LP
Regency Credit Facility		Regency’s $1.2 billion revolving credit facility
Regency Preferred Units		Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary
SEC		Securities and Exchange Commission
Southern Union		Southern Union Company
Southern Union Merger		ETE’s acquisition of Southern Union on March 26, 2012
SUGS		Southern Union Gas Services
Sunoco		Sunoco, Inc.
Sunoco Logistics		Sunoco Logistics Partners L.P.
Sunoco Merger		ETP’s acquisition of Sunoco on October 5, 2012
Transwestern		Transwestern Pipeline Company, LLC
WTI		West Texas Intermediate Crude

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation of ETP’s Propane Business and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

 

		September 30, 2013				December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,177			$	372
Accounts receivable, net			3,546				3,057
Accounts receivable from related companies			51				71
Inventories			1,697				1,522
Exchanges receivable			43				55
Price risk management assets			36				25
Current assets held for sale			16				184
Other current assets			321				311
Total current assets			6,887				5,597
PROPERTY, PLANT AND EQUIPMENT			32,623				30,388
ACCUMULATED DEPRECIATION			(2,949	)			(2,104	)
			29,674				28,284
NON-CURRENT ASSETS HELD FOR SALE			145				985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			4,087				4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS			20				43
GOODWILL			6,428				6,434
INTANGIBLE ASSETS, net			2,195				2,291
OTHER NON-CURRENT ASSETS, net			607				533
Total assets		$	50,043			$	48,904

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)

 

		September 30, 2013				December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	3,544			$	3,107
Accounts payable to related companies			11				15
Exchanges payable			190				156
Price risk management liabilities			69				115
Accrued and other current liabilities			1,922				1,754
Current maturities of long-term debt			298				613
Current liabilities held for sale			13				85
Total current liabilities			6,047				5,845
NON-CURRENT LIABILTIES HELD FOR SALE			70				142
LONG-TERM DEBT, less current maturities			22,011				21,440
PREFERRED UNITS			—				331
DEFERRED INCOME TAXES			3,708				3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES			78				162
OTHER NON-CURRENT LIABILITIES			893				995
COMMITMENTS AND CONTINGENCIES (Note 14)
PREFERRED UNITS OF SUBSIDIARY			32				73
EQUITY:
General Partner			(2	)			—
Limited Partners:
Common Unitholders			1,401				2,125
Accumulated other comprehensive income (loss)			1				(12	)
Total partners’ capital			1,400				2,113
Noncontrolling interest			15,804				14,237
Total equity			17,204				16,350
Total liabilities and equity		$	50,043			$	48,904

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
REVENUES:
Natural gas sales		$	915			$	734			$	2,752			$	1,791
NGL sales			968				585				2,468				1,705
Crude sales			4,215				—				11,408				—
Gathering, transportation and other fees			786				627				2,341				1,712
Refined product sales			4,633				—				13,945				—
Other			969				158				2,814				443
Total revenues			12,486				2,104				35,728				5,651
COSTS AND EXPENSES:
Cost of products sold			11,064				1,228				31,436				3,205
Operating expenses			403				208				1,127				614
Depreciation and amortization			332				211				962				571
Selling, general and administrative			158				98				499				353
Total costs and expenses			11,957				1,745				34,024				4,743
OPERATING INCOME			529				359				1,704				908
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized			(298	)			(237	)			(913	)			(732	)
Bridge loan related fees			—				—				—				(62	)
Equity in earnings of unconsolidated affiliates			38				21				182				118
Gain on deconsolidation of Propane Business			—				—				—				1,057
Losses on extinguishment of debt			—				—				(7	)			(123	)
Gains (losses) on interest rate derivatives			3				(6	)			55				(23	)
Gain on sale of AmeriGas common units			87				—				87				—
Other, net			33				(3	)			—				28
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE			392				134				1,108				1,171
Income tax expense from continuing operations			49				26				136				33
INCOME FROM CONTINUING OPERATIONS			343				108				972				1,138
Income (loss) from discontinued operations			13				(142	)			44				(136	)
NET INCOME (LOSS)			356				(34	)			1,016				1,002
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST			205				(69	)			648				747
NET INCOME ATTRIBUTABLE TO PARTNERS			151				35				368				255
GENERAL PARTNER’S INTEREST IN NET INCOME			1				—				1				1
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	150			$	35			$	367			$	254
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic		$	0.52			$	0.23			$	1.24			$	1.06
Diluted		$	0.52			$	0.23			$	1.24			$	1.06
NET INCOME PER LIMITED PARTNER UNIT:
Basic		$	0.54			$	0.13			$	1.31			$	0.97
Diluted		$	0.54			$	0.13			$	1.31			$	0.97

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

(unaudited)

 

		Three Months Ended   September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Net income (loss)		$	356			$	(34	)		$	1,016			$	1,002
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges			(3	)			(7	)			(5	)			(15	)
Change in value of derivative instruments accounted for as cash flow hedges			(4	)			(7	)			4				14
Change in value of available-for-sale securities			1				—				1				—
Actuarial gain relating to pension and other postretirement benefits			8				—				9				—
Foreign currency translation adjustment			—				—				(1	)			—
Change in other comprehensive income from equity investments			9				8				13				(14	)
			11				(6	)			21				(15	)
Comprehensive income (loss)			367				(40	)			1,037				987
Less: Comprehensive income (loss) attributable to noncontrolling interest			213				(67	)			660				739
Comprehensive income attributable to partners		$	154			$	27			$	377			$	248

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2013

(Dollars in millions)

(unaudited)

 

		General Partner				Common Unitholders				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interest				Total
Balance, December 31, 2012		$	—			$	2,125			$	(12	)		$	14,237			$	16,350
Distributions to partners			(1	)			(543	)			—				—				(544	)
Distributions to noncontrolling interest			—				—				—				(1,050	)			(1,050	)
Subsidiary units issued for cash			—				96				—				1,354				1,450
Subsidiary units issued in certain acquisitions			(1	)			(506	)			—				507				—
Non-cash compensation expense, net of units tendered by employees for tax withholdings			—				4				—				44				48
Capital contributions from noncontrolling interest			—				—				—				15				15
Other, net			(1	)			(1	)			4				(4	)			(2	)
Conversion of Regency Preferred Units for Regency Common Units			—				—				—				41				41
Deemed distribution related to SUGS Transaction			—				(141	)			—				—				(141	)
Other comprehensive income, net of tax			—				—				9				12				21
Net income			1				367				—				648				1,016
Balance, September 30, 2013		$	(2	)		$	1,401			$	1			$	15,804			$	17,204

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

 

		Nine Months Ended September 30,
		2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	1,016			$	1,002
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization			962				571
Deferred income taxes			244				37
Gain on curtailment of other postretirement benefit plans			—				(15	)
Amortization of finance costs charged to interest			(43	)			6
Bridge loan related fees			—				62
Non-cash compensation expense			43				34
Gain on deconsolidation of Propane Business			—				(1,057	)
Gain on sale of AmeriGas common units			(87	)			—
Write-down of assets included in loss from discontinued operations			—				145
Losses on extinguishment of debt			7				123
LIFO valuation adjustments			(22	)			—
Equity in earnings of unconsolidated affiliates			(182	)			(118	)
Distributions from unconsolidated affiliates			269				153
Other non-cash			22				74
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation (see Note 2)			(382	)			(120	)
Net cash provided by operating activities			1,847				897
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received			—				(2,972	)
Cash paid for all other acquisitions, net of cash received			(5	)			(10	)
Cash proceeds from the sale of MGE assets, net (See Note 2)			973				—
Cash proceeds from the sale of AmeriGas common units			346				—
Capital expenditures (excluding allowance for equity funds used during construction)			(2,504	)			(2,239	)
Contributions in aid of construction costs			11				28
Contributions to unconsolidated affiliates			(3	)			(35	)
Distributions from unconsolidated affiliates in excess of cumulative earnings			326				139
Proceeds from the sale of assets			72				35
Cash proceeds from contribution of propane operations			—				1,443
Other			(49	)			(2	)
Net cash used in investing activities			(833	)			(3,613	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			9,768				9,081
Repayments of long-term debt			(9,439	)			(6,144	)
Subsidiary equity offerings, net of issue costs			1,450				1,084
Distributions to partners			(544	)			(491	)
Debt issuance costs			(56	)			(99	)
Distributions to noncontrolling interest			(1,050	)			(688	)
Capital contributions received from noncontrolling interest			15				24
Redemption of Preferred Units			(340	)			—
Other, net			(13	)			(5	)
Net cash provided by (used in) financing activities			(209	)			2,762
INCREASE IN CASH AND CASH EQUIVALENTS			805				46
CASH AND CASH EQUIVALENTS, beginning of period			372				126
CASH AND CASH EQUIVALENTS, end of period		$	1,177			$	172

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts, except per unit data, are in millions)

(unaudited)

1.    OPERATIONS AND ORGANIZATION:

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

The consolidated financial statements of ETE presented herein include the results of operations of:

 

•

the Parent Company;

 

•

our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”); and

 

•

ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 19 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:

 

•

ETP’s operations are conducted through the following subsidiaries:

 

•

ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.

 

•

Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of:

 

•

Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

 

•

ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.

 

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•

ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.

 

•

CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.

 

•

ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

 

•

Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets.

 

•

Holdco, a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows:

 

•

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. As discussed in Note 2, on April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interests in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. Additionally, as discussed in Note 2, on September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company.

 

•

Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores primarily on the east coast and in the midwest region of the United States.

 

•

Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

Our reportable segments reflect the following reportable business segments:

 

•

Investment in ETP, including the consolidated operations of ETP.

 

•

Investment in Regency, including the consolidated operations of Regency.

 

•

Corporate and Other, including the following:

 

•

activities of the Parent Company; and

 

•

the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2012, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of September 30, 2013 and for the three months ended September 30, 2013 and 2012, have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations,

 

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maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2013, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2013 and 2012. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012, as filed with the SEC on March 1, 2013.

Certain prior period amounts have been reclassified to conform to the 2013 presentation. These reclassifications had no impact on net income or total equity.

As a result of the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

2.    ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Sale of Distribution Operations

In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). As of January 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc., assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allows a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division, subject to certain approvals.

Effective September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. The sale of Southern Union’s NEG division is expected to close in the fourth quarter of 2013 for cash proceeds of $40 million, subject to customary post-closing adjustments and the assumption of $20 million of debt.

The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The assets and liabilities of the LDC Disposal Group have been classified as assets and liabilities held for sale.

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the

 

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Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments. As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

Sunoco Merger

On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and $2.6 billion in cash.

Regency’s Acquisition of PVR Partners, L.P.

On October 10, 2013, Regency and PVR Partners, L.P. (“PVR”) announced the approval of a merger agreement, pursuant to which Regency intends to propose to acquire PVR. This acquisition will be a unit-for-unit transaction plus a one-time $40 million cash payment to PVR unitholders which represents total consideration of $5.6 billion, including the assumption of net debt of $1.8 billion. The holders of PVR common units, PVR Class B Units and PVR Special Units (“PVR Unit(s)”) will receive 1.02 Regency common units in exchange for each PVR Unit held on the applicable record date. The transaction is subject to the approval of PVR’s unitholders, Hart-Scott-Rodino Antitrust Improvements Act approval and other customary closing conditions. The transaction is expected to close in the first quarter of 2014.

3.    INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:

 

•

AmeriGas. ETP received approximately 30 million AmeriGas common units in connection with the Partnership’s contribution of its retail propane operations to AmeriGas in January 2012. On July 12, 2013, ETP sold 7.5 million of its AmeriGas common units for net proceeds of $346 million. ETP currently owns approximately 22 million AmeriGas common units.

 

•

Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, an approximate 5,400 mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.

 

•

FEP. ETP owns a 50% interest in the FEP, which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.

 

•

HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.

 

•

MEP. Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

 

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•

PES. Sunoco owns an approximate 30% non-operating interest in PES, a joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia. Sunoco has a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Revenue		$	5,208			$	1,840			$	14,710			$	4,251
Operating income			163				273				803				807
Net income			21				111				409				376

In addition to the equity method investments described above, ETP and Regency have other equity method investments, which are not significant to our consolidated financial statements.

4.    CASH AND CASH EQUIVALENTS:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

Non-cash investing and financing activities are as follows:

 

		Nine Months Ended September 30,
		2013				2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures		$	260			$	432
Net gains (losses) from subsidiary common unit transactions		$	(410	)		$	33
AmeriGas limited partner interest received in Propane Contribution		$	—			$	1,123
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger		$	—			$	2,354
Subsidiary issuances of common units in connection with certain acquisitions		$	—			$	112

5.    INVENTORIES:

Inventories consisted of the following:

 

		September 30, 2013				December 31, 2012
Natural gas and NGLs		$	513			$	338
Crude oil			464				418
Refined products			517				572
Other			203				194
Total inventories		$	1,697			$	1,522

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

 

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6.    FAIR VALUE MEASUREMENTS:

We have commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of September 30, 2013 and December 31, 2012 was $22.96 billion and $24.15 billion, respectively. As of September 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.31 billion and $22.05 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:

 

		Fair Value Measurements at September 30, 2013
		Fair Value Total				Level 1				Level 2				Level 3
Assets:
Interest rate derivatives		$	43			$	—			$	43			$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX			4				4				—				—
Swing Swaps IFERC			1				—				1				—
Fixed Swaps/Futures			90				84				6				—
Options—Calls			1				—				1				—
Forward Physical Contracts			1				—				1				—
NGLs—Forwards/Swaps			10				9				1				—
Power—Forwards			2				—				2				—
Refined Products—Futures			25				25				—				—
Total commodity derivatives			134				122				12				—
Total Assets		$	177			$	122			$	55			$	—

 

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		Fair Value Measurements at September 30, 2013
		Fair Value Total				Level 1				Level 2				Level 3
Liabilities:
Interest rate derivatives		$	(112	)		$	—			$	(112	)		$	—
Embedded derivatives in the Regency Preferred Units			(23	)			—				—				(23	)
Commodity derivatives:
Condensate—Forward Swaps			(2	)			—				(2	)			—
Natural Gas:
Basis Swaps IFERC/NYMEX			(8	)			(8	)			—				—
Swing Swaps IFERC			(2	)			—				(2	)			—
Fixed Swaps/Futures			(59	)			(58	)			(1	)			—
Options—Calls			(1	)			—				(1	)			—
NGLs—Forwards/Swaps			(10	)			(8	)			(2	)			—
Power:
Forwards			(1	)			—				(1	)			—
Options—Calls			(2	)			—				(2	)			—
Refined Products—Futures			(16	)			(16	)			—				—
Crude—Futures			(2	)			(2	)			—				—
Total commodity derivatives			(103	)			(92	)			(11	)			—
Total Liabilities		$	(238	)		$	(92	)		$	(123	)		$	(23	)

 

		Fair Value Measurements at December 31, 2012
		Fair Value Total				Level 1				Level 2				Level 3
Assets:
Interest rate derivatives		$	55			$	—			$	55			$	—
Commodity derivatives:
Condensate—Forward Swaps			2				—				2				—
Natural Gas:
Basis Swaps IFERC/NYMEX			11				11				—				—
Swing Swaps IFERC			3				—				3				—
Fixed Swaps/Futures			98				94				4				—
Options—Calls			3				—				3				—
Options—Puts			1				—				1				—
Forward Physical Contracts			1				—				1				—
NGLs—Swaps			2				1				1				—
Power:
Forwards			27				—				27				—
Futures			1				1				—				—
Options—Calls			2				—				2				—
Refined Products—Futures			5				1				4				—
Total commodity derivatives			156				108				48				—
Total Assets		$	211			$	108			$	103			$	—

 

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		Fair Value Measurements at December 31, 2012
		Fair Value Total				Level 1				Level 2				Level 3
Liabilities:
Interest rate derivatives		$	(235	)		$	—			$	(235	)		$	—
Preferred Units			(331	)			—				—				(331	)
Embedded derivatives in the Regency Preferred Units			(25	)			—				—				(25	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX			(18	)			(18	)			—				—
Swing Swaps IFERC			(2	)			—				(2	)			—
Fixed Swaps/Futures			(103	)			(94	)			(9	)			—
Options—Calls			(3	)			—				(3	)			—
Options—Puts			(1	)			—				(1	)			—
NGLs—Swaps			(4	)			(3	)			(1	)			—
Power:
Forwards			(27	)			—				(27	)			—
Futures			(2	)			(2	)			—				—
Refined Products—Futures			(8	)			(1	)			(7	)			—
Total commodity derivatives			(168	)			(118	)			(50	)			—
Total Liabilities		$	(759	)		$	(118	)		$	(285	)		$	(356	)

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the nine months ended September 30, 2013. There were no transfers between the fair value hierarchy levels during the nine months ended September 30, 2013 or 2012.

 

Balance, December 31, 2012		$	(356	)
Realized loss included in other income (expense)			(9	)
Net unrealized gain included in other income (expense)			2
Redemption of Preferred Units			340
Balance, September 30, 2013		$	(23	)

7.    NET INCOME PER LIMITED PARTNER UNIT:

A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:

 

		Three Months Ended   September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Income from continuing operations		$	343			$	108			$	972			$	1,138
Less: Income from continuing operations attributable to noncontrolling interest			195				45				623				860
Income from continuing operations, net of noncontrolling interest			148				63				349				278
Less: General Partner’s interest in income from continuing operations			1				—				1				—
Income from continuing operations available to Limited Partners		$	147			$	63			$	348			$	278

 

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		Three Months Ended   September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units			280.7				280.0				280.4				262.3
Basic income from continuing operations per Limited Partner unit		$	0.52			$	0.23			$	1.24			$	1.06
Basic income (loss) from discontinued operations per Limited Partner unit		$	0.02			$	(0.10	)		$	0.07			$	(0.09	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners		$	147			$	63			$	348			$	278
Dilutive effect of equity-based compensation of subsidiaries			—				—				(1	)			(1	)
Diluted income from continuing operations available to Limited Partners		$	147			$	63			$	347			$	277
Weighted average limited partner units			280.7				280.0				280.4				262.3
Diluted income from continuing operations per Limited Partner unit		$	0.52			$	0.23			$	1.24			$	1.06
Diluted income (loss) from discontinued operations per Limited Partner unit		$	0.02			$	(0.10	)		$	0.07			$	(0.09	)

8.    DEBT OBLIGATIONS:

Parent Company Indebtedness

The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.

Term Loan

On March 23, 2012, ETE entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, as Administrative Agent, and the other lenders from time to time party thereto (the “Term Lenders”), which became effective on March 26, 2012. The Term Credit Agreement has a scheduled maturity date of March 26, 2017, with an option for ETE to extend the term subject to the terms and conditions set forth therein. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2 billion. Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of ETE for each interest period. The applicable margin for LIBOR rate loans is 3.00% and the applicable margin for base rate loans is 2.00%. Proceeds of the borrowings under the Term Credit Agreement were used to partially fund the Southern Union Merger, to repay amounts outstanding under the Parent Company Credit Facility, and to pay transaction fees and expenses related to the Southern Union Merger, the new Term Credit Agreement and other transactions incidental thereto.

During the nine months ended September 30, 2013, proceeds from ETP’s acquisition of ETE’s 60% interest in Holdco were used to repay borrowings of $1.10 billion on ETE’s Term Credit Agreement. The total amount outstanding as of September 30, 2013 was $900 million.

 

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Revolving Credit Facility

As of September 30, 2013, there were no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

Senior Notes

The Parent Company currently has outstanding on aggregate of $1.80 billion in principal amount of 7.5% Senior Notes due 2020 (the “ETE Notes”).

Refinancing Activities

On October 30, 2013, the Parent Company commenced an offer to purchase for cash up to $400 million aggregate principal amount outstanding of the ETE Notes pursuant to the Offer to Purchase Statement dated October 30, 2013, which tender offer amount may be increased at the discretion of the Parent Company. The tender offer is subject to a financing condition, and the Parent Company may obtain financing for purchases of ETE Notes in the tender offer pursuant to the issuance of new senior notes, borrowings under a new term loan facility or other debt financings. In this regard, the Parent Company has also announced that it has launched a syndication of a new senior secured term loan credit facility to refinance its existing term loan facility under the Term Credit Agreement. The Parent Company is also arranging a new five-year revolving credit facility for up to $600 million.

Subsidiary Indebtedness

Regency Senior Notes

In April 2013, in conjunction with Southern Union’s contribution of SUGS to Regency, Regency issued $600 million aggregate principal amount of senior notes in a private placement that mature November 2023 and bear interest at 4.5% payable semi-annually. At any time prior to August 2023, Regency may redeem some or all of the senior notes due 2023 at a price equal to 100% of the principal amount plus a make-whole premium and accrued interest. On or after August 1, 2023, Regency may redeem some or all of the senior notes due 2023 at a price equal to 100% plus accrued interest.

 

In June 2013, Regency redeemed all of the $163 million outstanding 9.375% Senior Notes due 2016 for $178 million cash, including accrued and unpaid interest of $7 million and other fees and expenses.

In September 2013, Regency issued $400 million aggregate principal amount of senior notes that mature September 2020 and bear interest at 5.75% payable semi-annually. Regency used the net proceeds of approximately $394 million from the offering to repay borrowings outstanding under the Regency Credit Facility.

ETP Senior Notes

In January 2013, ETP issued $800 million aggregate principal amount of 3.6% Senior Notes due February 2023 and $450 million aggregate principal amount of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly-owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

 

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Sunoco Logistics Senior Notes

In January 2013, Sunoco Logistics issued $350 million aggregate principal amount of 3.45% Senior Notes due January 2023 and $350 million aggregate principal amount of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.

ETP Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

Subsidiary Credit Facilities

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility which expires in October 2016. Indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. There were no outstanding borrowings under the ETP Credit Facility as of September 30, 2013.

Regency Credit Facility

In May 2013, Regency entered into an amendment to the Regency Credit Facility to increase the borrowing capacity of the Regency Credit Facility to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. Indebtedness under the Regency Credit Facility is secured by all of Regency’s and certain of its subsidiaries’ tangible and intangible assets and guaranteed by certain of Regency’s subsidiaries.

As of September 30, 2013, the Regency Credit Facility had a balance outstanding of $176 million in revolving credit loans and approximately $15 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2013, which was reduced by any letters of credit, was approximately $1.01 billion, and the weighted average interest rate on the total amount outstanding as of September 30, 2013 was 2.19%.

Southern Union Credit Facilities

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2014. There were no outstanding borrowings under these credit facilities as of September 30, 2013.

 

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West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility which expires in April 2015. Outstanding borrowings under this credit facility were $35 million as of September 30, 2013.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2013.

9.    PREFERRED UNITS:

On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units from Regency GP Acquirer L.P. (“GE Regency”) pursuant to a Preferred Unit Redemption Agreement, dated as of March 28, 2013, between ETE and GE Regency. Prior to the Redemption, on March 28, 2013, ETE paid GE Regency $40 million in cash in exchange for GE Regency relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.

In July 2013, certain holders of the Regency Preferred Units exercised their right to convert an aggregate 2,459,017 Series A Preferred Units into 2,629,223 Regency Common Units. Concurrent with this transaction, a gain of $26 million was recognized in other, net, related to the embedded derivative. As of September 30, 2013, the remaining Series A Preferred Units were convertible into 2,047,571 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon.

10.    EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the nine months ended September 30, 2013 was as follows:

 

		Number of Units
Outstanding at December 31, 2012			280.0
Issuance of restricted units under equity incentive plans			0.8
Outstanding at September 30, 2013			280.8

Sales of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from the issuance or redemption of units by ETP or Regency (excluding transactions with the Parent Company) as capital transactions.

As a result of ETP’s and Regency’s issuances of common units during the nine months ended September 30, 2013, we recognized decreases in partners’ capital of $410 million.

Sales of Common Units by ETP

In January 2013 and May 2013, ETP entered into Equity Distribution Agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the nine months ended September 30, 2013, ETP received proceeds of $568 million, net of commissions of $6 million, from the issuance of units pursuant to the Equity Distribution Agreements, which proceeds were used for general partnership purposes. ETP also received $13 million, net of

 

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commissions, in October 2013 from the settlement of transactions initiated in September 2013 under these agreements. Approximately $426 million of ETP Common Units remain available to be issued under these agreements.

During the nine months ended September 30, 2013, distributions of $76 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.6 million ETP Common Units. As of September 30, 2013, a total of 2.7 million ETP Common Units remain available to be issued under the existing registration statement.

In April 2013, ETP issued 13.8 million ETP Common Units at $48.05 per ETP Common Unit in an underwritten public offering. Net proceeds of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.

As discussed in “ETP Class H Units” below, ETP redeemed and cancelled 50.2 million of its common units in connection with the issuance of Class H Units to ETE.

ETP Class G Units

In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in ETP’s consolidated financial statements.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into among ETP, ETE and ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE (“ETE Holdings”), ETP redeemed and cancelled 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H Units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.

 

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Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

 

Quarter Ended		Record Date		Payment Date		Rate
December 31, 2012		February 7, 2013		February 19, 2013		$	0.6350
March 31, 2013		May 6, 2013		May 17, 2013			0.6450
June 30, 2013		August 5, 2013		August 19, 2013			0.6550
September 30, 2013		November 4, 2013		November 19, 2013			0.6725

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:

 

Quarter Ended		Record Date		Payment Date		Rate
December 31, 2012		February 7, 2013		February 14, 2013		$	0.89375
March 31, 2013		May 6, 2013		May 15, 2013			0.89375
June 30, 2013		August 5, 2013		August 14, 2013			0.89375
September 30, 2013		November 4, 2013		November 14, 2013			0.90500

Following are incentive distributions ETE has agreed to relinquish:

 

•

In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of the incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

 

•

In conjunction with the Holdco transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

 

•

As discussed in Note 2, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

 

•

As discussed under “ETP Class H Units” above, ETP has agreed to make incremental cash distributions in the aggregate amount of $329 million to ETE Holdings, over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H Units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

 

		Quarters Ending
		March 31				June 30				September 30				December 31				Total Year
2013			N/A				N/A			$	21.00			$	21.00			$	42.00
2014		$	27.25			$	27.25				27.25				27.25				109.00
2015			13.25				13.25				13.25				13.25				53.00
2016			5.50				5.50				5.50				5.50				22.00

 

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Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

 

Quarter Ended		Record Date		Payment Date		Rate
December 31, 2012		February 7, 2013		February 14, 2013		$	0.460
March 31, 2013		May 6, 2013		May 13, 2013			0.460
June 30, 2013		August 5, 2013		August 14, 2013			0.465
September 30, 2013		November 4, 2013		November 14, 2013			0.470

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

 

Quarter Ended		Record Date		Payment Date		Rate
December 31, 2012		February 8, 2013		February 14, 2013		$	0.5450
March 31, 2013		May 9, 2013		May 15, 2013			0.5725
June 30, 2013		August 8, 2013		August 14, 2013			0.6000
September 30, 2013		November 8, 2013		November 14, 2013			0.6300

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive income (loss), net of tax:

 

		September 30, 2013				December 31, 2012
Net gains (losses) on commodity related hedges		$	—			$	(3	)
Available-for-sale securities			1				—
Foreign currency translation adjustment			(1	)			—
Actuarial loss related to pensions and other postretirement benefits			(1	)			(10	)
Equity investments, net			4				(9	)
Subtotal			3				(22	)
Amounts attributable to noncontrolling interest			(2	)			10
Total accumulated other comprehensive income (loss), net of tax		$	1			$	(12	)

11.    UNIT-BASED COMPENSATION PLANS:

We and certain of our subsidiaries have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase common units, restricted units, phantom units, DERs, common unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

During the nine months ended September 30, 2013, an equity award relating to 750,000 ETE Common Units was granted to an ETE employee and equity awards relating to 6,042 ETE Common Units were granted to ETE directors. The weighted average grant-date fair value of these awards was $55.95 per unit. As of September 30, 2013, a total of 804,190 unit awards remain subject to vesting or other conditions. We expect to recognize a total of $39 million in compensation expense over a weighted average period of 4.3 years related to unvested awards.

 

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ETP Unit-Based Compensation Plans

During the nine months ended September 30, 2013, ETP employees were granted a total of 1,142,663 unvested awards with five-year service vesting requirements, and directors were granted a total of 9,060 unvested awards with three-year and five-year service vesting requirements. The weighted average grant-date fair value of these awards was $45.74 per unit. As of September 30, 2013, a total of 2,840,725 unit awards remain unvested, for which ETP expects to recognize $72 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Regency Unit-Based Compensation Plans

During the nine months ended September 30, 2013, Regency employees and directors were granted 52,360 Regency phantom units with five-year service vesting requirements. As of September 30, 2013, a total of 1,168,247 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $23.41 per unit. Regency expects to recognize a total of $20 million in compensation expense over a weighted average period of 3.5 years related to Regency’s unvested phantom units.

Sunoco Logistics Unit-Based Compensation Plan

As of September 30, 2013, a total of 918,031 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $16 million in compensation expense over a weighted-average period of 2.4 years.

12.    INCOME TAXES:

The following table summarizes the Partnership’s income tax expense from continuing operations:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Income tax expense from continuing operations		$	49			$	26			$	136			$	33
Effective tax rate			13	%			19	%			12	%			3	%

The decrease in the effective tax rate for the three months ended September 30, 2013 compared to the same period last year was primarily due to Southern Union’s non-deductible executive compensation as a result of the Southern Union Merger in 2012. The increase in the effective tax rate for the nine months ended September 30, 2013 compared to the same period last year is primarily due to the Partnership conducting a significant portion of its activities through its corporate subsidiaries, Southern Union and Sunoco, subsequent to the mergers and related transactions that occurred in 2012. The Southern Union Merger was completed in the first quarter of 2012 and the Holdco Transaction and Sunoco Merger were completed in the fourth quarter 2012.

Sunoco has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco’s 2004 through 2011 open statute years, Sunoco has proposed to the Internal Revenue Service (“IRS”) that these government incentive payments be excluded from federal taxable income. A successful claim could result in significant tax refunds for multiple years. However, a thorough evaluation of the ultimate financial impact to Sunoco is complex and requires significant analysis, including the ramifications of tax indemnification agreements with certain former Sunoco affiliates which were members of Sunoco’s consolidated federal return group during these years. At this time, a benefit for the claim is not estimable and has not been recorded in the financial statements.

 

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13.    RETIREMENT BENEFITS:

The following table sets forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:

 

		Three Months Ended September 30,
		2013								2012(1)
		Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost		$	—			$	(1	)		$	1			$	—
Interest cost			10				2				2				1
Expected return on plan assets			(15	)			(3	)			(3	)			(2	)
Prior service cost amortization			—				1				—				—
Actuarial loss amortization			1				—				—				—
			(4	)			(1	)			—				(1	)
Regulatory adjustment(2)			1				—				3				1
Net periodic benefit cost		$	(3	)		$	(1	)		$	3			$	—

 

		Nine Months Ended September 30,
		2013								2012(1)
		Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost		$	5			$	—			$	2			$	—
Interest cost			28				5				5				1
Expected return on plan assets			(45	)			(7	)			(6	)			(3	)
Prior service cost amortization			—				1				—				—
Actuarial loss amortization			2				—				—				—
Settlement credits			(2	)			—				—				—
Curtailment recognition(3)			—				—				—				(15	)
			(12	)			(1	)			1				(17	)
Regulatory adjustment(2)			5				—				6				1
Net periodic benefit cost		$	(7	)		$	(1	)		$	7			$	(16	)

 

(1)	The three and nine months ended September 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

(2)

Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its MGE and NEG divisions. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

(3)

Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

 

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14.    REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Audit

The FERC recently completed an audit of PEPL, a subsidiary of Southern Union, for the period from January 1, 2010 through December 31, 2011, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. An audit report was received in August 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.

Contingent Residual Support Agreement—AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2013, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022.

PEPL Holdings Guarantee of Collection

In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023.

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $33 million and $12 million for the three months ended September 30, 2013 and 2012, respectively, which include contingent rentals totaling $8 million in the three months ended September 30, 2013. For the nine months ended September 30, 2013 and 2012, rental expense for operating leases totaled $98 million and $31 million, respectively, which include contingent rentals totaling $18 million in the nine months ended September 30, 2013. During the three and nine months ended September 30, 2013, $6 million and $16 million, respectively, of rental expense was recovered through related sublease rental income.

Certain of our subsidiaries’ joint venture agreements require that they fund their proportionate shares of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of

 

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business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

Sunoco Litigation

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder

 

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Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.

MTBE Litigation

Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases, injunctive relief, punitive damages and attorneys’ fees.

As of September 30, 2013, Sunoco is a defendant in six cases, including one initiated by the State of New Jersey and another by the Commonwealth of Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. The two state cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.

Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Litigation Relating to the PVR Merger

Four putative class action lawsuits challenging the merger have been filed, two in the Court of Chancery of the State of Delaware: (i) David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL); and (ii) Robert P. Frutkin v. Edward B. Cloues II, et al. (Case No. 9020-VCL), and two in the Court of Common Pleas for Delaware County, Pennsylvania: (i) Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606); and (ii) Steven Keene v. James L. Gardner, et al. (Case No. 2013-010723). All of the cases name PVR, PVR GP, LLC (“PVR GP”), the current directors of PVR GP, Regency, the General Partner and Merger Sub as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process. The lawsuits allege further that PVR GP, Regency, the General Partner, and Merger Sub aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties. The Naiditch and Monatt lawsuits allege further that PVR also aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties. The lawsuits seek, in general, (i) injunctive relief enjoining the transactions contemplated by the merger agreement, (ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs’ costs, including reasonable attorneys’ and experts’ fees, (iv) the accounting by the defendants to plaintiffs for all damages caused by the defendants and (v) such further relief as the court deems just and proper. These lawsuits are at a preliminary stage and it is not possible to predict the ultimate outcome of any of these lawsuits. However, PVR, Regency and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.

 

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Other Litigation and Contingencies

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The parties agreed to settle the matter and executed a memorandum of understanding. On October 4, 2013, the Court approved the settlement and ordered the case dismissed with prejudice.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2013 and December 31, 2012, accruals of approximately $38 million and $42 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

No amounts have been recorded in our September 30, 2013 or December 31, 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Litigation Related to Incident at JJ’s Restaurant. On February 19, 2013, there was a natural gas explosion at JJ’s Restaurant located at 910 W. 48th Street in Kansas City, Missouri. Effective September 1, 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc. (“Laclede”), assumed any and all liability arising from this incident in ETP’s sale of the assets of MGE to Laclede.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the

 

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propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

 

•

Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.

 

•

Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

 

•

Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.

 

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•

Currently operating Sunoco retail sites.

 

•

Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

 

•

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2013, Sunoco had been named as a PRP at 39 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

 

		September 30, 2013				December 31, 2012
Current		$	40			$	46
Non-current			192				166
Total environmental liabilities		$	232			$	212

During the three and nine months ended September 30, 2013, the Partnership recorded $9 million and $27 million, respectively, of expenditures related to environmental cleanup programs.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule was required by October 2013, and the Partnership believes it is in compliance.

 

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On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.

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. 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 future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

15.    PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by operating entity.

ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s derivatives being recorded directly in

 

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earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP’s trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP’s transportation and storage segment’s operations and are netted in cost of products sold in the consolidated statements of operations. Additionally, ETP also has trading activities related to power in ETP’s “All Other” segment which are also netted in cost of products sold. As a result of ETP’s trading activities and the use of derivative financial instruments in ETP’s transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to ETP’s risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’s commodity risk management policy.

Derivatives are utilized in ETP’s midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.

 

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The following table details ETP’s outstanding commodity-related derivatives:

 

		September 30, 2013								December 31, 2012
		Notional Volume				Maturity				Notional Volume				Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures			6,560,000				2013-2019				—				—
Basis Swaps IFERC/NYMEX(1)			(27,402,500	)			2013-2017				(30,980,000	)			2013-2014
Swing Swaps			1,690,000				2013-2016				—				—
Power (Megawatt):
Forwards			562,250				2013				19,650				2013
Futures			97,212				2013				(1,509,300	)			2013
Options—Calls			(1,700	)			2013				1,656,400				2013
Crude (Bbls)—Futures			80,000				2013				—				—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX			(5,300,000	)			2013-2014				150,000				2013
Swing Swaps IFERC			6,965,000				2013-2016				(83,292,500	)			2013
Fixed Swaps/Futures			(14,072,500	)			2013-2015				27,077,500				2013
Forward Physical Contracts			(11,663,485	)			2013-2014				11,689,855				2013-2014
Natural Gas Liquid (Bbls)—Forwards/Swaps			(1,182,000	)			2013-2014				(30,000	)			2013
Refined Products (Bbls)—Futures			(93,327	)			2013-2014				(666,000	)			2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX			(6,577,500	)			2013				(18,655,000	)			2013
Fixed Swaps/Futures			(47,215,000	)			2014				(44,272,500	)			2013
Hedged Item—Inventory			47,215,000				2014				44,272,500				2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX			(1,150,000	)			2013				—				—
Fixed Swaps/Futures			(5,720,000	)			2013				(8,212,500	)			2013
Natural Gas Liquid (Bbls)—Forwards/Swaps			(720,000	)			2013				(930,000	)			2013
Crude (Bbls)—Futures			(120,000	)			2013				—				—
Refined Products (Bbls)—Futures			—				—				(98,000	)			2013

 

(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

We expect gains of $1 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in

 

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operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

The following table details Regency’s outstanding commodity-related derivatives:

 

		September 30, 2013								December 31, 2012
		Notional Volume				Maturity				Notional Volume				Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures			15,176,000				2013-2014				8,395,000				2013-2014
Propane (Gallons):
Forwards/Swaps			33,642,000				2013-2014				3,318,000				2013
Natural Gas Liquids (Barrels):
Forwards/Swaps			144,000				2013-2014				243,000				2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps			829,000				2013-2014				356,000				2014

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. Southern Union also uses treasury rate locks to manage interest rate risk associated with long term borrowings.

The following table summarizes our interest rate swaps outstanding none of which were designated as hedges for accounting purposes:

 

Notional Amount Outstanding

Entity

Term

Type(1)

September 30, 2013

December 31, 2012

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

$

—

$

500

ETP

July 2013(2)

Forward-starting to pay a fixed rate of 4.03% and receive a floating rate

—

400

ETP

July 2014(2)

Forward-starting to pay a fixed rate of 4.25% and receive a floating rate

400

400

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

600

ETP

June 2021

Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%

200

—

ETP

February 2023

Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%

400

—

Southern Union

November 2016

Pay a fixed rate of 2.97% and receive a floating rate

25

75

Southern Union

November 2021

Pay a fixed rate of 3.75% and receive a floating rate

450

450

 

(1)	Floating rates are based on 3-month LIBOR.

(2)

Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. During the nine months ended September 30, 2013, ETP settled $400 million of forward-starting interest rate swaps that had an effective date of July 2013.

 

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Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

ETP utilizes master-netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of September 30, 2013 would be $7 million, which would be reduced by $2 million, due to the netting feature.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a summary of our derivative assets and liabilities:

 

		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)		$	16			$	8			$	(3	)		$	(10	)
			16				8				(3	)			(10	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)		$	112			$	110			$	(95	)		$	(116	)
Commodity derivatives			39				40				(38	)			(44	)
Current assets held for sale			—				1				—				—
Non-current assets held for sale			—				1				—				—
Current liabilities held for sale			—				—				—				(9	)
Interest rate derivatives			43				55				(112	)			(235	)
Embedded derivatives in Regency Preferred Units			—				—				(23	)			(25	)
			194				207				(268	)			(429	)
Total derivatives		$	210			$	215			$	(271	)		$	(439	)

 

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In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

 

				Asset Derivatives								Liability Derivatives
		Balance Sheet Location		September 30, 2013				December 31, 2012				September 30, 2013				December 31, 2012
Derivatives in offsetting agreements:
OTC contracts		Price risk management asset (liability)		$	37			$	28			$	(38	)		$	(27	)
Broker cleared derivative contracts		Other current assets (liabilities)			170				149				(159	)			(221	)
					207				177				(197	)			(248	)
Offsetting agreements:
Collateral paid to OTC counterparties		Other current assets (liabilities)			—				—				—				2
Counterparty netting		Price risk management asset (liability)			(32	)			(25	)			32				25
Payments on margin deposit		Other current assets (liabilities)			(15	)			—				34				59
					(47	)			(25	)			66				86
Net derivatives with offsetting agreements					160				152				(131	)			(162	)
Derivatives without offsetting agreements					50				63				(140	)			(277	)
Total derivatives				$	210			$	215			$	(271	)		$	(439	)

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:

 

		Change in Value Recognized in OCI on Derivatives (Effective Portion)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	(4	)		$	11			$	4			$	16
Interest rate derivatives			—				(5	)			—				15
Total		$	(4	)		$	6			$	4			$	31

 

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		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
				Three Months Ended September 30,								Nine Months Ended September 30,
				2013				2012				2013				2012
Derivatives in cash flow hedging relationships:
Commodity derivatives		Cost of products sold		$	3			$	9			$	5			$	25
Total				$	3			$	9			$	5			$	25

 

		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
				Three Months Ended September 30,								Nine Months Ended September 30,
				2013				2012				2013				2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives		Cost of products sold		$	—			$	10			$	4			$	29
Total				$	—			$	10			$	4			$	29

 

		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income on Derivatives
				Three Months Ended September 30,								Nine Months Ended September 30,
				2013				2012				2013				2012
Derivatives not designated as hedging instruments:
Commodity derivatives—Trading		Cost of products sold		$	(11	)		$	4			$	(12	)		$	(7	)
Commodity derivatives—Non-Trading		Cost of products sold			(34	)			(48	)			(20	)			(36	)
Commodity derivatives—Non-Trading		Deferred gas purchases			—				—				(3	)			—
Interest rate derivatives		Gains (losses) on interest rate derivatives			3				(6	)			55				(23	)
Embedded derivatives		Other income			24				2				2				10
Total				$	(18	)		$	(48	)		$	22			$	(56	)

16.    RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 18).

 

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17.    OTHER INFORMATION:

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:

 

		September 30, 2013				December 31, 2012
Deposits paid to vendors		$	55			$	41
Prepaid expenses and other			266				270
Total other current assets		$	321			$	311

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

		September 30, 2013				December 31, 2012
Interest payable		$	346			$	334
Customer advances and deposits			70				61
Accrued capital expenditures			288				427
Accrued wages and benefits			200				250
Taxes payable other than income taxes			294				208
Income taxes payable			82				41
Deferred income taxes			243				130
Deferred revenue			2				—
Other			397				303
Total accrued and other current liabilities		$	1,922			$	1,754

18.    REPORTABLE SEGMENTS:

As a result of the Holdco Acquisition in April 2013, our reportable segments were re-evaluated and currently reflect the following reportable segments:

 

•

Investment in ETP, including the consolidated operations of ETP;

 

•

Investment in Regency, including the consolidated operations of Regency; and

 

•

Corporate and Other, including the following:

 

•

activities of the Parent Company; and

 

•

the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

We previously reported net income as a measure of segment performance. Due to the change in our reportable segments described above, the financial information available to our chief operating decision maker to assess the performance is now based on Segment Adjusted EBITDA. Therefore, we have accordingly revised our segment operating performance measure that we report. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation

 

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expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 2, Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.

Eliminations in the tables below include the following:

 

•

ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.

 

•

ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Because the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Segment Adjusted EBITDA:
Investment in ETP		$	942			$	660			$	2,967			$	1,796
Investment in Regency			172				141				446				398
Corporate and Other			(9	)			(7	)			(38	)			(48	)
Adjustments and Eliminations			(56	)			(40	)			(111	)			(83	)
Total			1,049				754				3,264				2,063
Depreciation and amortization			(332	)			(211	)			(962	)			(571	)
Interest expense, net of interest capitalized			(298	)			(237	)			(913	)			(732	)
Bridge loan related fees			—				—				—				(62	)
Gain on deconsolidation of Propane Business			—				—				—				1,057
Gain on sale of AmeriGas common units			87				—				87				—
Gains (losses) on interest rate derivatives			3				(6	)			55				(23	)
Non-cash unit-based compensation expense			(16	)			(10	)			(43	)			(34	)
Unrealized gains (losses) on commodity risk management activities			22				4				45				(43	)
Losses on extinguishment of debt			—				—				(7	)			(123	)
Gain on curtailment of other postretirement benefit plans			—				—				—				15
LIFO valuation adjustments			6				—				22				—
Equity in earnings of unconsolidated affiliates			38				21				182				118
Adjusted EBITDA related to unconsolidated affiliates			(165	)			(148	)			(553	)			(429	)
Adjusted EBITDA related to discontinued operations			(12	)			(32	)			(75	)			(66	)
Other, net			10				(1	)			6				1
Income from continuing operations before income tax expense		$	392			$	134			$	1,108			$	1,171

 

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		September 30, 2013				December 31, 2012
Total assets:
Investment in ETP		$	43,556			$	43,230
Investment in Regency			8,566				8,123
Corporate and Other			779				707
Adjustments and Eliminations			(2,858	)			(3,156	)
Total		$	50,043			$	48,904

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Revenues:
Investment in ETP:
Revenues from external customers		$	11,848			$	1,791			$	34,214			$	4,697
Intersegment revenues			54				11				93				24
			11,902				1,802				34,307				4,721
Investment in Regency:
Revenues from external customers			633				526				1,796				1,406
Intersegment revenues			32				1				48				7
			665				527				1,844				1,413
Adjustments and Eliminations			(81	)			(225	)			(423	)			(483	)
Total revenues		$	12,486			$	2,104			$	35,728			$	5,651

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Regency.

Investment in ETP

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Intrastate Transportation and Storage		$	502			$	503			$	1,711			$	1,402
Interstate Transportation and Storage			296				309				973				761
Midstream			683				757				2,021				1,845
NGL Transportation and Services			537				157				1,303				459
Investment in Sunoco Logistics			4,502				—				12,215				—
Retail Marketing			5,297				—				15,805				—
All Other			85				76				279				254
Total revenues			11,902				1,802				34,307				4,721
Less: Intersegment revenues			54				11				93				24
Revenues from external customers		$	11,848			$	1,791			$	34,214			$	4,697

 

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Investment in Regency

 

		Three Months Ended   September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Gathering and Processing		$	603			$	475			$	1,671			$	1,262
Contract Services			58				47				159				137
Corporate and others			4				5				14				14
Total revenues			665				527				1,844				1,413
Less: Intersegment revenues			32				1				48				7
Revenues from external customers		$	633			$	526			$	1,796			$	1,406

19.    SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

(unaudited)

 

		September 30, 2013				December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	100			$	9
Accounts receivable from related companies			7				11
Other current assets			1				3
Total current assets			108				23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			4,003				6,094
INTANGIBLE ASSETS, net			15				19
GOODWILL			9				9
NOTE RECEIVABLE FROM AFFILIATE			—				166
OTHER NON-CURRENT ASSETS, net			50				56
Total assets		$	4,185			$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	8			$	1
Accounts payable to related companies			27				15
Interest payable			62				48
Price risk management liabilities			—				5
Accrued and other current liabilities			—				1
Current maturities of long-term debt			4				4
Total current liabilities			101				74
LONG-TERM DEBT, less current maturities			2,683				3,840
PREFERRED UNITS			—				331
OTHER NON-CURRENT LIABILITIES			1				9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner			(2	)			—
Limited Partners			1,401				2,125
Accumulated other comprehensive income (loss)			1				(12	)
Total partners’ capital			1,400				2,113
Total liabilities and partners’ capital		$	4,185			$	6,367

 

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STATEMENTS OF OPERATIONS

(unaudited)

 

		Three Months Ended         September 30,								Nine Months Ended         September 30,
		2013				2012				2013				2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(11	)		$	(7	)		$	(40	)		$	(48	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized			(47	)			(64	)			(164	)			(170	)
Bridge loan related fees			—				—				—				(62	)
Gains (losses) on interest rate derivatives			3				(6	)			9				(15	)
Equity in earnings of unconsolidated affiliates			207				118				573				552
Other, net			(1	)			(6	)			(11	)			(2	)
INCOME BEFORE INCOME TAXES			151				35				367				255
Income tax benefit			—				—				(1	)			—
NET INCOME			151				35				368				255
GENERAL PARTNER’S INTEREST IN NET INCOME			1				—				1				1
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	150			$	35			$	367			$	254

 

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STATEMENTS OF CASH FLOWS

(unaudited)

 

		Nine Months Ended September 30,
		2013				2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	650			$	406
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in (paid for) acquisitions and other transactions, net			1,332				(1,113	)
Contributions to affiliate			(8	)			(445	)
Note receivable from affiliate			—				(221	)
Payments received on note receivable from affiliate			166				55
Net cash provided by (used in) investing activities			1,490				(1,724	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			440				2,028
Principal payments on debt			(1,603	)			(141	)
Distributions to partners			(544	)			(491	)
Redemption of Preferred Units			(340	)			—
Debt issuance costs			(2	)			(78	)
Net cash provided by (used in) financing activities			(2,049	)			1,318
DECREASE IN CASH AND CASH EQUIVALENTS			91				—
CASH AND CASH EQUIVALENTS, beginning of period			9				18
CASH AND CASH EQUIVALENTS, end of period		$	100			$	18

 

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INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

 

		Page
Report of Independent Registered Public Accounting Firm			F-47
Consolidated Balance Sheets—December 31, 2012 and 2011			F-48
Consolidated Statements of Operations—Years Ended December 31, 2012, 2011 and 2010			F-50
Consolidated Statements of Comprehensive Income—Years Ended December 31, 2012, 2011 and 2010			F-51
Consolidated Statements of Equity—Years Ended December 31, 2012, 2011 and 2010			F-52
Consolidated Statements of Cash Flows—Years Ended December 31, 2012, 2011 and 2010			F-53
Notes to Consolidated Financial Statements			F-54

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Energy Transfer Equity, L.P.

We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, as of December 31, 2012 and for the period from October 5, 2012 to December 31, 2012, which statements reflect total assets constituting 21 percent of consolidated total assets as of December 31, 2012, and total revenues of 19 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P., is based solely on the report of the other auditors. We did not audit the consolidated financial statements of Regency Energy Partners LP, a consolidated subsidiary, for the period from May 26, 2010 to December 31, 2010, which statements reflect total revenues of 11 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Regency Energy Partners LP for the period from May 26, 2010 to December 31, 2010, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 15, the accompanying consolidated financial statements have been adjusted to reflect a change in the Partnership’s reportable segments.

/s/ GRANT THORNTON LLP

Dallas, Texas

March 1, 2013 (except for Note 15, as to which the date is November 13, 2013)

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

 

		December 31,
		2012				2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	372			$	126
Accounts receivable, net of allowance for doubtful accounts of $2 and $9 as of December 31, 2012 and 2011, respectively			3,057				680
Accounts receivable from related companies			71				100
Inventories			1,522				328
Exchanges receivable			55				21
Price risk management assets			25				16
Current assets held for sale			184				—
Other current assets			311				184
Total current assets			5,597				1,455
PROPERTY, PLANT AND EQUIPMENT			30,388				16,530
ACCUMULATED DEPRECIATION			(2,104	)			(1,971	)
			28,284				14,559
NON-CURRENT ASSETS HELD FOR SALE			985				—
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			4,737				1,497
NON-CURRENT RISK MANAGEMENT ASSETS			43				26
GOODWILL			6,434				2,039
INTANGIBLE ASSETS, net			2,291				1,072
OTHER NON-CURRENT ASSETS, net			533				249
Total assets		$	48,904			$	20,897

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

 

		December 31,
		2012				2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	3,107			$	512
Accounts payable to related companies			15				33
Exchanges payable			156				18
Price risk management liabilities			115				90
Accrued and other current liabilities			1,754				764
Current maturities of long-term debt			613				424
Current liabilities held for sale			85				—
Total current liabilities			5,845				1,841
NON-CURRENT LIABILITIES HELD FOR SALE			142				—
LONG-TERM DEBT, less current maturities			21,440				10,947
DEFERRED INCOME TAXES			3,566				217
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES			162				81
PREFERRED UNITS (Note 7)			331				323
OTHER NON-CURRENT LIABILITIES			995				29
COMMITMENTS AND CONTINGENCIES (Note 11)
PREFERRED UNITS OF SUBSIDIARY (Note 7)			73				71
EQUITY:
General Partner			—				—
Limited Partners:
Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding as of December 31, 2012 and 2011, respectively)			2,125				52
Accumulated other comprehensive income (loss)			(12	)			1
Total partners’ capital			2,113				53
Noncontrolling interest			14,237				7,335
Total equity			16,350				7,388
Total liabilities and equity		$	48,904			$	20,897

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

 

		Years Ended December 31,
		2012				2011				2010
REVENUES:
Natural gas sales		$	2,705			$	2,982			$	2,730
NGL sales			2,253				1,716				826
Crude sales			2,872				—				—
Gathering, transportation and other fees			2,386				1,819				1,360
Refined product sales			5,299				—				—
Other			1,449				1,673				1,640
Total revenues			16,964				8,190				6,556
COSTS AND EXPENSES:
Cost of products sold			13,088				5,169				4,102
Operating expenses			1,065				906				771
Depreciation and amortization			871				586				406
Selling, general and administrative			580				292				233
Total costs and expenses			15,604				6,953				5,512
OPERATING INCOME			1,360				1,237				1,044
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized			(1,018	)			(740	)			(625	)
Bridge loan related fees			(62	)			—				—
Equity in earnings of unconsolidated affiliates			212				117				65
Gain on deconsolidation of Propane Business			1,057				—				—
Losses on extinguishments of debt			(123	)			—				(16	)
Losses on non-hedged interest rate derivatives			(19	)			(78	)			(52	)
Impairments of investments in affiliates			—				(5	)			(53	)
Other, net			30				17				(4	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE			1,437				548				359
Income tax expense from continuing operations			54				17				14
INCOME FROM CONTINUING OPERATIONS			1,383				531				345
Loss from discontinued operations			(109	)			(3	)			(8	)
NET INCOME			1,274				528				337
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST			970				218				144
NET INCOME ATTRIBUTABLE TO PARTNERS			304				310				193
GENERAL PARTNER’S INTEREST IN NET INCOME			2				1				1
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	302			$	309			$	192
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic		$	1.17			$	1.39			$	0.87
Diluted		$	1.17			$	1.38			$	0.87
NET INCOME PER LIMITED PARTNER UNIT:
Basic		$	1.13			$	1.39			$	0.86
Diluted		$	1.13			$	1.38			$	0.86

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

 

		Years Ended December 31,
		2012				2011				2010
Net income		$	1,274			$	528			$	337
Other comprehensive income, net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges			(17	)			(19	)			49
Change in value of derivative instruments accounted for as cash flow hedges			12				7				19
Change in value of available-for-sale securities			—				(1	)			(4	)
Change in other comprehensive income from equity investments			(9	)			—				—
Actuarial loss relating to pension and other postretirement benefits			(10	)			—				—
			(24	)			(13	)			64
Comprehensive income			1,250				515				401
Less: Comprehensive income attributable to noncontrolling interest			959				209				150
Comprehensive income attributable to partners		$	291			$	306			$	251

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

 

		General Partner				Common Unitholders				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interest				Total
Balance, December 31, 2009		$	—			$	53			$	(53	)		$	3,220			$	3,220
Regency Transactions (See Note 3)			1				209				—				1,895				2,105
Distributions to partners			(1	)			(482	)			—				—				(483	)
Distributions to noncontrolling interest			—				—				—				(568	)			(568	)
Subsidiary units issued for cash			—				142				—				1,410				1,552
Non-cash compensation expense, net of units tendered by employees for tax withholdings			—				1				—				25				26
Other, net			—				(1	)			—				(5	)			(6	)
Other comprehensive income, net of tax			—				—				58				6				64
Net income			1				192				—				144				337
Balance, December 31, 2010			1				114				5				6,127				6,247
Distributions to partners			(2	)			(524	)			—				—				(526	)
Distributions to noncontrolling interest			—				—				—				(779	)			(779	)
Subsidiary units issued for cash			—				153				—				1,750				1,903
Subsidiary units issued in acquisition			—				—				—				3				3
Non-cash compensation expense, net of units tendered by employees for tax withholdings			—				1				—				33				34
Other, net			—				(1	)			—				(8	)			(9	)
Other comprehensive income, net of tax			—				—				(4	)			(9	)			(13	)
Net income			1				309				—				218				528
Balance, December 31, 2011			—				52				1				7,335				7,388
Distributions to partners			(2	)			(664	)			—				—				(666	)
Distributions to noncontrolling interest			—				—				—				(1,017	)			(1,017	)
Units issued in Southern Union Merger (See Note 3)			—				2,354				—				—				2,354
Subsidiary units issued for cash			—				33				—				1,070				1,103
Subsidiary units issued in acquisitions			—				47				—				2,248				2,295
Non-cash compensation expense, net of units tendered by employees for tax withholdings			—				1				—				31				32
Capital contributions from noncontrolling interest			—				—				—				42				42
Holdco Transaction (see Note 3)			—				—				—				3,580				3,580
Other, net			—				—				—				(11	)			(11	)
Other comprehensive loss, net of tax			—				—				(13	)			(11	)			(24	)
Net income			2				302				—				970				1,274
Balance, December 31, 2012		$	—			$	2,125			$	(12	)		$	14,237			$	16,350

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

 

		Years Ended December 31,
		2012				2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	1,274			$	528			$	337
Reconciliation of net income to net cash provided by operating activities:
Impairments of investments in affiliates			—				5				53
Payment for termination of Parent Company interest rate derivatives			—				—				(169	)
Proceeds from termination of ETP interest rate derivatives			—				—				26
Depreciation and amortization			871				586				406
Deferred income taxes			51				1				4
Gain on curtailment of other postretirement benefit plans			(15	)			—				—
Amortization of finance costs charged to interest			(13	)			20				18
Bridge loan related fees			62				—				—
Non-cash compensation expense			47				42				31
Gain on deconsolidation of Propane Business			(1,057	)			—				—
Losses on extinguishments of debt			123				—				16
Losses on disposal of assets			4				1				5
Equity in earnings of unconsolidated affiliates			(212	)			(117	)			(65	)
Distributions from unconsolidated affiliates			208				126				149
LIFO valuation reserve			75				—				—
Other non-cash			211				28				17
Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation (see Note 2)			(551	)			158				260
Net cash provided by operating activities			1,078				1,378				1,088
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received (See Note 3)			(2,972	)			—				—
Cash received from (paid) all other acquisitions			(10	)			(1,972	)			(345	)
Capital expenditures (excluding allowance for equity funds used during construction)			(3,271	)			(1,810	)			(1,510	)
Contributions in aid of construction costs			35				25				14
Contributions to unconsolidated affiliates			(37	)			(222	)			(93	)
Distributions from unconsolidated affiliates in excess of cumulative earnings			189				72				—
Proceeds from sale of disposal group			207				—				—
Proceeds from the sale of assets			44				33				104
Cash proceeds from contribution of propane operations			1,443				—				—
Other			176				—				—
Net cash used in investing activities			(4,196	)			(3,874	)			(1,830	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			12,870				8,262				4,389
Repayments of long-term debt			(8,848	)			(6,264	)			(4,078	)
Subsidiary equity offerings, net of issue costs			1,103				1,903				1,552
Distributions to partners			(666	)			(526	)			(483	)
Distributions to noncontrolling interests			(1,017	)			(779	)			(568	)
Debt issuance costs			(112	)			(53	)			(49	)
Capital contributions received from noncontrolling interest			42				—				—
Other, net			(8	)			(7	)			(3	)
Net cash provided by financing activities			3,364				2,536				760
INCREASE IN CASH AND CASH EQUIVALENTS			246				40				18
CASH AND CASH EQUIVALENTS, beginning of period			126				86				68
CASH AND CASH EQUIVALENTS, end of period		$	372			$	126			$	86

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts, except per unit data, are in millions)

1.    OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2012, 2011 and 2010, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through the date the financial statements were issued.

We obtained control of Regency on May 26, 2010 as a result of the Regency Transactions. On March 26, 2012, we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57 million ETE Common Units. On October 5, 2012, ETP completed the Sunoco Merger and we and ETP also completed the Holdco Transaction at that time. See Note 3 for more information regarding the Regency Transactions, the Southern Union Merger, Sunoco Merger and Holdco Transaction.

At December 31, 2012, our equity interests in Regency and ETP consisted of:

 

		General Partner Interest (as a % of total partnership interest)				Incentive Distribution Rights (“IDRs”)				Limited Partner Units
ETP			0.9	%			100	%			50,226,967
Regency			1.6	%			100	%			26,266,791

The consolidated financial statements of ETE presented herein include the results of operations of:

 

•

the Parent Company;

 

•

our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);

 

•

Holdco, in which we own a 60% interest and ETP owns the remaining 40%, which includes the operations of Southern Union and Sunoco; and

 

•

ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

As a result of the Regency Transactions in May 2010, the Southern Union Merger in March 2012 and the Sunoco Merger in October 2012, the periods presented herein do not include activities from Regency, Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

 

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Certain prior period amounts have been reclassified to conform to the 2012 presentation. In October 2012, we sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. Canyon was previously included in our midstream operations. In December 2012, Southern Union entered into a purchase and sale agreement pursuant to which subsidiaries of Laclede Gas Company, Inc. have agreed to acquire the assets of Southern Union’s Missouri Gas Energy and New England Gas Company divisions. For the period from March 26, 2012 to December 31, 2012 the results of operations of distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

Business Operations

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union in March 2012, the Parent Company also generated cash flows through its wholly-owned subsidiary, Southern Union until its contribution of Southern Union to Holdco on October 5, 2012. Subsequent to October 5, 2012, we also generate cash flows from our direct investment in Holdco. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:

 

•

ETP’s operations are conducted through the following subsidiaries:

 

•

ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. Our intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.

 

•

ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

 

•

Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

 

•

ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.

 

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•

ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.

 

•

CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., which owns 100% of the FGT interstate natural gas pipeline.

 

•

ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

 

•

Sunoco Logistics is a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets.

 

•

Holdco is a Delaware limited liability company that is owned 40% and 60% by ETP and ETE, respectively. Holdco directly owns Southern Union and Sunoco. Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. As such, ETP consolidates Holdco (including Sunoco and Southern Union) in its financial statements which their operations are described as follows:

 

•

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States.

 

•

Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores in 25 states, primarily on the east coast and in the midwest region of the United States.

 

•

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

As discussed in Note 15 to our consolidated financial statement, subsequent to the Holdco Acquisition on April 30, 2013, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; and Corporate and Other.

2.    ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Certain of our significant accounting policies have been impacted by current year transactions. See Note 3 for a discussion of these transactions.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between

 

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estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

Our intrastate transportation and storage and interstate transportation and storage operations’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.

Our intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream operations’ marketing activities, and from producers at the wellhead.

In addition, our intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Results from the midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing

 

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services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in our midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third party pipeline, which is when title and risk of loss pass to the customer.

We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Our retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. In addition some of Sunoco’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.

Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, (iii) contract compression services and (iv) contract treating services. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria

 

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outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties. Regency generally reports revenue gross when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers.

Regulatory Accounting—Regulatory Assets and Liabilities

Our interstate transportation and storage operations are subject to regulation by certain state and federal authorities and has accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Southern Union records regulatory assets with respect to its distribution operations. We recorded regulatory assets with respect to Southern Union’s distribution operations, which have been classified as discontinued operations as of December 31, 2012. At December 31, 2012, we had $123 million of regulatory assets included in the consolidated balance sheet as non-current assets held for sale. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application of regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

 

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The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:

 

		Years Ended December 31,
		2012				2011				2010
Accounts receivable		$	267			$	6			$	92
Accounts receivable from related companies			(9	)			(24	)			(26	)
Inventories			(258	)			51				15
Exchanges receivable			14				1				1
Other current assets			597				(51	)			33
Other non-current assets, net			(129	)			7				6
Accounts payable			(989	)			21				(67	)
Accounts payable to related companies			92				6				(10	)
Exchanges payable			—				2				(4	)
Accrued and other current liabilities			(159	)			84				74
Other non-current liabilities			26				—				—
Price risk management assets and liabilities, net			(3	)			55				146
Net change in operating assets and liabilities, net of effects of acquisitions, dispositions and deconsolidation		$	(551	)		$	158			$	260

Non-cash investing and financing activities and supplemental cash flow information were as follows:

 

		Years Ended December 31,
		2012				2011				2010
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures		$	420			$	226			$	108
Net gain from subsidiary common unit transactions		$	80			$	153			$	352
AmeriGas limited partner interest received in Propane Contribution (see Note 4)		$	1,123			$	—			$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger (see Note 3)		$	2,354			$	—			$	—
Long-term debt assumed and non-compete agreement notes payable issued from acquisitions		$	6,658			$	4			$	1,243
Subsidiary issuance of Common Units in connection with certain acquisitions		$	2,295			$	3			$	584
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized		$	997			$	728			$	547
Cash paid for income taxes		$	23			$	27			$	9

Accounts Receivable

Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral). Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and specific identification.

 

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Inventories

Inventories consist principally of natural gas held in storage, crude oil, petroleum and chemical products. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:

 

		December 31,
		2012				2011
Natural gas and NGLs, excluding propane		$	338			$	146
Propane			—				87
Crude oil			418				—
Refined products			572				—
Appliances, parts and fittings and other			194				95
Total inventories		$	1,522			$	328

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of designated hedged inventory is recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.

Other Current Assets

Other current assets consisted of the following:

 

		December 31,
		2012				2011
Deposits paid to vendors		$	41			$	66
Prepaid and other			270				118
Total other current assets		$	311			$	184

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or

 

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natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

We and our subsidiaries review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $128 million during the year ended December 31, 2012.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an AFUDC is accrued. Interest is capitalized based on the current borrowing rate when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts—borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

 

		December 31,
		2012				2011
Land and improvements		$	553			$	137
Buildings and improvements (5 to 40 years)			587				279
Pipelines and equipment (5 to 83 years)			19,505				11,359
Natural gas and NGL storage facilities (5 to 46 years)			1,057				790
Bulk storage, equipment and facilities (5 to 83 years)			1,745				977
Tanks and other equipment (10 to 40 years)			1,194				644
Retail equipment (3 to 99 years)			258				—
Vehicles (3 to 25 years)			96				231
Right of way (20 to 83 years)			2,134				793
Furniture and fixtures (3 to 12 years)			50				48
Linepack			118				59
Pad gas			58				58
Other (2 to 19 years)			1,060				234
Construction work-in-process			1,973				921
			30,388				16,530
Less—Accumulated depreciation			(2,104	)			(1,971	)
Property, plant and equipment, net		$	28,284			$	14,559

We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:

 

		Years Ended December 31,
		2012				2011				2010
Depreciation expense(1)		$	801			$	531			$	370
Capitalized interest, excluding AFUDC		$	99			$	13			$	4

 

(1)	Depreciation expense amounts have been adjusted by $26 million and $25 million for the years ended December 31, 2011 and 2010, respectively, to present Canyon’s operations as discontinued operations.

 

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Advances to and Investments in Affiliates

Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control the investee’s operating and financial policies.

See Note 4 for a discussion of these joint ventures.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations, as of November 30 for the Southern Union reporting units and as of December 31 for all others, including all of Regency’s reporting units. No goodwill impairments were recorded for the periods presented in these consolidated financial statements.

Changes in the carrying amount of goodwill were as follows:

 

		Balance, December 31, 2010				Goodwill acquired				Balance, December 31, 2011				Goodwill acquired				Disposal of Goodwill(1)				Balance, December 31, 2012
ETP Intrastate Transportation and Storage		$	10			$	—			$	10			$	—			$	—			$	10
ETP Interstate Transportation and Storage			99				—				99				1,785				—				1,884
ETP Midstream			50				—				50				338				—				388
ETP NGL Transportation and Services			—				432				432				—				—				432
ETP Retail Marketing			—				—				—				1,272				—				1,272
Investment in Sunoco Logistics			—				—				—				1,368				—				1,368
Investment in Regency			790				—				790				—				—				790
Corporate and Other			652				6				658				384				(752	)			290
Total		$	1,601			$	438			$	2,039			$	5,147			$	(752	)		$	6,434

 

(1)	Includes goodwill deconsolidated or disposed of during the year ended December 31, 2012 and goodwill reclassified to non-current assets held for sale at December 31, 2012.

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. A net increase in goodwill of $4.40 billion was recorded during the year ended December 31, 2012, primarily due to $2.64 billion from the Sunoco Merger and $2.50 billion related to Southern Union, offset by $619 million in goodwill that was contributed as part of the deconsolidation of ETP’s Propane Business, and $133 million classified as assets held for sale. This additional goodwill is not expected to be deductible for tax purposes.

See further discussion regarding our acquisitions at Note 3.

 

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Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheets the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows:

 

		December 31, 2012								December 31, 2011
		Gross Carrying Amount				Accumulated Amortization				Gross Carrying Amount				Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)		$	2,032			$	(150	)		$	1,059			$	(135	)
Trade names (20 years)			66				(8	)			66				(5	)
Noncompete agreements (3 to 15 years)			—				—				15				(8	)
Patents (9 years)			48				(1	)			1				—
Other (10 to 15 years)			4				(1	)			1				(1	)
Total amortizable intangible assets			2,150				(160	)			1,142				(149	)
Non-amortizable intangible assets:
Trademarks			301				—				79				—
Total intangible assets		$	2,451			$	(160	)		$	1,221			$	(149	)

During 2012, in connection with the Southern Union Merger and Holdco Transaction, we recorded customer contracts of $1.07 billion with useful lives ranging from 5 to 20 years, patents of $48 million with useful lives of 10 years and non-amortizable trademarks of $301 million.

Aggregate amortization expense of intangibles assets was as follows:

 

		Years Ended December 31,
		2012				2011				2010
Reported in depreciation and amortization		$	70			$	55			$	36

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

 

Years Ending December 31:
2013		$	116
2014			115
2015			115
2016			115
2017			115

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

 

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Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

 

		December 31,
		2012				2011
Unamortized financing costs (3 to 30 years)		$	152			$	132
Regulatory assets			93				89
Deferred charges			140				—
Other			148				28
Total other non-current assets, net		$	533			$	249

Asset Retirement Obligation

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably determine the settlement dates.

Except for the AROs of Southern Union, Sunoco Logistics and Sunoco discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2012 and 2011 because the settlement dates were indeterminable. Although a number of other onshore assets in Southern Union’s system are subject to agreements or regulations that give rise to an ARO upon Southern Union’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco has legal asset retirement obligations for several other assets at its refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Below is a schedule of AROs by entity recorded as other non-current liabilities in ETP’s consolidated balance sheet as of December 31, 2012:

 

Southern Union		$	46
Sunoco			53
Sunoco Logistics			41
		$	140

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists.

 

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Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have has in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2012, there were no legally restricted funds for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

		December 31,
		2012				2011
Interest payable		$	334			$	204
Customer advances and deposits			61				101
Accrued capital expenditures			427				229
Accrued wages and benefits			250				80
Taxes payable other than income taxes			208				79
Income taxes payable			41				15
Deferred income taxes			130				—
Other			303				56
Total accrued and other current liabilities		$	1,754			$	764

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions.

 

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Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of December 31, 2012 and 2011 was $24.15 billion and $12.21 billion, respectively. As of December 31, 2012 and 2011, the aggregate carrying amount of our consolidated debt obligations was $22.05 billion and $11.37 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2012 and 2011 based on inputs used to derive their fair values:

 

		Fair Value Measurements at December 31, 2012
		Fair Value Total				Level 1				Level 2				Level 3
Assets:
Interest rate derivatives		$	55			$	—			$	55			$	—
Commodity derivatives:
Condensate—Forward Swaps			2				—				2				—
Natural Gas:
Basis Swaps IFERC/NYMEX			11				11				—				—
Swing Swaps IFERC			3				—				3				—
Fixed Swaps/Futures			98				94				4				—
Options—Calls			3				—				3				—
Options—Puts			1				—				1				—
Forward Physical Contracts			1				—				1				—
NGLs:
Swaps			2				1				1				—
Power:
Forwards			27				—				27				—
Futures			1				1				—				—
Options—Calls			2				—				2				—
Refined Products			5				1				4				—
Total commodity derivatives			156				108				48				—
Total Assets		$	211			$	108			$	103			$	—

 

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		Fair Value Measurements at December 31, 2012
		Fair Value Total				Level 1				Level 2				Level 3
Liabilities:
Interest rate derivatives		$	(235	)		$	—			$	(235	)		$	—
Preferred Units			(331	)			—				—				(331	)
Embedded derivatives in the Regency Preferred Units			(25	)			—				—				(25	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX			(18	)			(18	)			—				—
Swing Swaps IFERC			(2	)			—				(2	)			—
Fixed Swaps/Futures			(103	)			(94	)			(9	)			—
Options—Calls			(3	)			—				(3	)			—
Options—Puts			(1	)			—				(1	)			—
NGLs—Swaps			(4	)			(3	)			(1	)			—
Power:
Forwards			(27	)			—				(27	)			—
Futures			(2	)			(2	)			—				—
Refined Products			(8	)			(1	)			(7	)			—
Total commodity derivatives			(168	)			(118	)			(50	)			—
Total Liabilities		$	(759	)		$	(118	)		$	(285	)		$	(356	)
		Fair Value Measurements at December 31, 2011 Using
		Fair Value Total				Level 1				Level 2				Level 3
Assets:
Marketable securities (included in other current assets)		$	1			$	1			$	—			$	—
Interest rate derivatives			36				—				36				—
Commodity derivatives:
Condensate—Forward Swaps			1				—				1				—
Natural Gas:
Basis Swaps IFERC/NYMEX			63				63				—				—
Swing Swaps IFERC			15				2				13				—
Fixed Swaps/Futures			219				215				4				—
Options—Puts			6				—				6				—
Forward Physical Swaps			1				—				1				—
Total commodity derivatives			305				280				25				—
Total Assets		$	342			$	281			$	61			$	—
Liabilities:
Interest rate derivatives		$	(117	)		$	—			$	(117	)		$	—
Series A Convertible Preferred Units			(323	)			—				—				(323	)
Embedded derivatives in the Regency Preferred Units			(39	)			—				—				(39	)
Commodity derivatives:
Condensate—Forward Swaps			(2	)			—				(2	)			—
Natural Gas:
Basis Swaps IFERC/NYMEX			(82	)			(82	)			—				—
Swing Swaps IFERC			(16	)			(3	)			(13	)			—
Fixed Swaps/Futures			(148	)			(148	)			—				—
Forward Physical Swaps			(1	)			—				(1	)			—
NGLs—Forward Swaps			(9	)			—				(9	)			—
Propane—Forward Swaps			(4	)			—				(4	)			—
Total commodity derivatives			(262	)			(233	)			(29	)			—
Total Liabilities		$	(741	)		$	(233	)		$	(146	)		$	(362	)

 

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The following table presents the material unobservable inputs used to estimate the fair value of the Preferred Units and the embedded derivatives in Regency’s Preferred Units:

 

		Unobservable Input		December 31, 2012
Preferred Units		Assumed Yield			6.11	%
Embedded derivatives in the Regency Preferred Units		Credit Spread			6.49	%
		Volatility			21.38	%

Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U. S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2012. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2012 or 2011.

 

Balance, December 31, 2011		$	(362	)
Net unrealized gains included in other income (expense)			6
Balance, December 31, 2012		$	(356	)

Contributions in Aid of Construction Cost

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $25 million, $40 million and $43 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income.

 

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Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon ETP’s or Regency’s issuance of respective ETP or Regency Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2012, 2011 and 2010, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. Holdco, formed via the Holdco Transaction (see Note 3), which includes Sunoco and Southern Union, is included amongst these corporate subsidiaries. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

See Note 10 for income tax disclosures.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the

 

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statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on non-hedged interest rate derivatives” in the consolidated statements of operations. See Note 12 for additional information related to interest rate derivatives.

Pensions and Other Postretirement Benefit Plans

Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in stockholders’ equity.

See Note 13 for additional related information.

Allocation of Income

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 8).

 

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3.    ACQUISITIONS AND RELATED TRANSACTIONS:

2012 Transactions

Southern Union Merger

On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union is the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE until our contribution to Holdco discussed below. The assets acquired as a result of this merger significantly expand our existing geographic footprint of natural gas pipeline and natural gas transportation capacity and into natural gas utilities distribution, and are complementary to the assets owned and operated by our other entities.

Under the terms of the merger agreement, Southern Union stockholders received a total of 56,982,160 ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.

Citrus Acquisition

In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.

In connection with the Citrus Acquisition, we relinquished our rights to an aggregate $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the merger.

Pursuant to the merger agreement, we also granted ETP a right of first offer with respect to any disposition by us or SUGS, a subsidiary of Southern Union that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

Sunoco Merger

On October 5, 2012, ETP completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and a total of approximately $2.6 billion in cash.

Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco’s interests in Sunoco Logistics were transferred to ETP.

Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in refined products pipelines. The crude oil pipeline business consists of crude oil pipelines located principally in Oklahoma and Texas. The terminal facilities business consists of refined products and crude oil terminal capacity at the Nederland Terminal on the Gulf Coast of Texas and capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey. The crude oil acquisition and marketing business, principally conducted in Oklahoma and Texas, involves the acquisition and marketing of crude oil and consists of crude oil transport trucks and crude oil truck unloading facilities.

 

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Prior to the Sunoco Merger, on September 8, 2012, Sunoco completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook facility continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco retained an approximately 30% non-operating noncontrolling interest. The fair value of Sunoco’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase will provide working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco entered into a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

Holdco Transaction

Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 Class F Units representing limited partner interests in ETP. The ETP Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per ETP Class F Unit per year, which is the current distribution level. Pursuant to a stockholders agreement between ETE and ETP, ETP controls Holdco. Consequently, ETP consolidated Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

Under the terms of the Holdco transaction agreement, ETE relinquished an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The relinquishment applied to the distribution paid with respect to the quarter ended September 30, 2012.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the Southern Union Merger and Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet presented as of December 31, 2012 reflects the purchase price allocations. Management is continuing to validate certain assumptions made in connection with the purchase price allocation of Sunoco. Certain amounts included in the purchase price allocation as of December 31, 2012 for Southern Union have been changed from amounts reflected as of March 31, 2012 based on management’s review of the valuation.

 

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The following table summarizes the assets acquired and liabilities assumed recognized as of the respective acquisition dates:

 

		Sunoco(1)				Southern Union(2)
Total current assets		$	7,312			$	556
Property, plant and equipment			6,686				6,242
Goodwill			2,641				2,497
Intangible assets			1,361				55
Investments in unconsolidated affiliates			240				2,023
Note receivable			821				—
Other assets			128				163
			19,189				11,536
Current liabilities			4,424				1,348
Long-term debt obligations, including current maturities			2,879				3,120
Deferred income taxes			1,762				1,419
Other non-current liabilities			769				284
Noncontrolling interest			3,580				—
			13,414				6,171
Total consideration			5,775				5,365
Cash received			2,714				37
Total consideration, net of cash received		$	3,061			$	5,328

 

(1)	Includes amounts recorded with respect to Sunoco Logistics.

(2)	Includes ETP’s acquisition of Citrus.

As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.

ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.

Propane Operations

On January 12, 2012, ETP contributed its propane operations, consisting of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 30 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.5 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.5 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.

 

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We have not reflected the Propane operations as discontinued operations as ETP has a continuing involvement in this business as a result of the investment in AmeriGas that was transferred to ETP as consideration for the transaction.

Discontinued Operations

In October 2012, ETP sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been adjusted to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012. Canyon was previously included in the midstream operations in the Investment in ETP segment.

In December 2012, Southern Union entered into a purchase and sale agreement with the Laclede Entities, pursuant to which Laclede Missouri has agreed to acquire the assets of Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division. Total consideration is expected to be $1.04 billion, subject to customary closing adjustments, less the assumption of approximately $19 million of debt. For the period from March 26, 2012 to December 31, 2012 the results of continuing operations of distribution operations have been reclassified to income from discontinued operations. The assets and liabilities of the disposal group have been reclassified and reported as assets and liabilities held for sale as of December 31, 2012.

Below is selected financial information related to Southern Union’s distribution operations for the period from March 26, 2012 to December 31, 2012:

 

Revenue from discontinued operations		$	324
Net loss of discontinued operations, excluding effect of taxes and overhead allocations			43

The goodwill allocated to the disposal group was $133 million at December 31, 2012.

SUGS Contribution

On February 27, 2013, Southern Union entered into a definitive contribution agreement to contribute to Regency all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration to be paid by Regency in connection with this transaction will consist of (i) the issuance of 31,372,419 Regency common units to Southern Union, (ii) the issuance of 6,274,483 Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units will have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. Upon the closing of the transaction, we will agree to forego all distributions with respect to our IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing. The transaction is expected to close in the second quarter of 2013.

2011 Transactions

LDH Acquisition

On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.98 billion in

 

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cash (the “LDH Acquisition”), including working capital adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price, while Regency contributed approximately $593 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.

Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH by Lone Star expands ETP and Regency’s asset portfolios by adding a NGL platform with storage, transportation and fractionation capabilities.

ETP accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are consolidated into our Investment in ETP segment, while Lone Star’s results are recorded as an equity method investment in our Investment in Regency reporting segment. Regency’s equity method investment in Lone Star is reflected by ETP as noncontrolling interest attributable to Lone Star. These amounts have been eliminated in our consolidated financial statements.

2010 Transactions

Regency Transactions

On May 26, 2010, we acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions. In the Regency Transactions, we:

 

•

acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million;

 

•

acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12 million ETP Common Units we previously owned; and

 

•

acquired 26 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

We accounted for the Regency Transactions using the purchase method of accounting. The purchase price was $305 million, which was the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.

Other Acquisitions

In March 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, ETP recorded customer contracts of $68 million and goodwill of $27 million.

In September 2010, Regency completed its acquisition of Zephyr, a Texas based field services company for approximately $193 million in cash. In connection with this transaction, Regency recorded intangible assets of $119 million and no goodwill.

 

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Dispositions

In July 2010, Regency sold its East Texas gathering and processing assets to an affiliate of Tristream Energy LLC for approximately $70 million in cash. The net loss from these assets is classified as discontinued operations in the consolidated statements of operations from the date of the Regency Transactions to the date of the sale.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the years ended 2012 and 2011 are presented as if the Sunoco Merger and Holdco Transaction had been completed on January 1, 2011 and the LDH Acquisition had been completed on January 1, 2010.

 

		Year Ended December 31,
		2012				2011				2010
Revenues		$	40,398			$	37,560			$	7,407
Net income			868				865				358
Net income attributable to partners			866				863				228
Basic net income (loss) per Limited Partner unit		$	3.09			$	3.08			$	1.02
Diluted net income (loss) per Limited Partner unit		$	3.09			$	3.08			$	1.02

The pro forma consolidated results of operations include adjustments to:

 

•

include the results of Lone Star beginning January 1, 2010 and Southern Union and Sunoco beginning January 1, 2011;

 

•

include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and

 

•

include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

4.    ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

AmeriGas Partners, L.P.

On January 12, 2012, ETP contributed its Propane Business to AmeriGas in exchange for approximately $1.46 billion in cash and approximately 30 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. In addition, AmeriGas assumed approximately $71 million of existing debt of the Propane Business. ETP recognized a gain on deconsolidation of $1.06 billion as a result of this transaction.

ETP’s investment in AmeriGas initially reflected $630 million in excess of the proportionate share of AmeriGas’ limited partners’ capital. Of this excess fair value, $289 million is being amortized over a weighted average period of 14 years and $341 million is being treated as equity method goodwill and non-amortizable intangible assets.

We have not reflected the Propane operations as discontinued operations as a result of ETP’s investment in AmeriGas.

In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.

 

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ETP’s investment in AmeriGas was $1.02 billion as of December 31, 2012 and was reflected in our Investment in ETP segment.

Citrus Corp.

ETP acquired a 50% interest in Citrus, which owns 100% of FGT on March 26, 2012. A subsidiary of Kinder Morgan, Inc. owns the remaining 50% interest in Citrus. In exchange for the interest in Citrus, Southern Union received $1.9 billion in cash and $105 million of ETP Common Units. ETP initially recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. ETP’s investment in Citrus was $1.98 billion at December 31, 2012 and is reflected in our Investment in ETP segment.

Fayetteville Express Pipeline LLC

ETP owns a 50% interest in FEP, which owns an approximately 185 mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.

Midcontinent Express Pipeline LLC

Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).

 

		December 31,
		2012				2011
Current assets		$	945			$	893
Property, plant and equipment, net			10,979				10,393
Other assets			2,677				962
Total assets		$	14,601			$	12,248
Current liabilities		$	1,662			$	1,548
Non-current liabilities			7,024				5,778
Equity			5,915				4,922
Total liabilities and equity		$	14,601			$	12,248

 

		Years Ended December 31,
		2012				2011				2010
Revenue		$	4,492			$	3,784			$	3,287
Operating income			863				928				716
Net income			491				536				506

 

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5.    NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of our Preferred Units, see Note 7. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Regency that would have resulted assuming the incremental units related to ETP’s or Regency’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.

The calculation below for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 7.

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

 

		Years Ended December 31,
		2012				2011				2010
Income from continuing operations		$	1,383			$	531			$	345
Less: Income from continuing operations attributable to noncontrolling interest			1,070				221				149
Income from continuing operations, net of noncontrolling interest			313				310				196
Less: General Partner’s interest in income from continuing operations			1				1				1
Income from continuing operations available to Limited Partners		$	312			$	309			$	195
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units			266,722,030				222,968,261				222,941,156
Basic income from continuing operations per Limited Partner unit		$	1.17			$	1.39			$	0.87
Basic loss from discontinued operations per Limited Partner unit		$	(0.04	)		$	—			$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners		$	312			$	309			$	195
Dilutive effect of equity-based compensation of subsidiaries			(1	)			(1	)			—
Diluted income from continuing operations available to Limited Partners			311				308				195
Weighted average limited partner units			266,722,030				222,968,261				222,941,156
Diluted income from continuing operations per Limited Partner unit		$	1.17			$	1.38			$	0.87
Diluted loss from discontinued operations per Limited Partner unit		$	(0.04	)		$	—			$	(0.01	)

 

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6.    DEBT OBLIGATIONS:

Our debt obligations consist of the following:

 

		December 31,
		2012				2011
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020		$	1,800			$	1,800
ETE Senior Secured Term Loan, due March 26, 2017			2,000				—
ETE Senior Secured Revolving Credit Facility			60				72
Other			19				1
Unamortized premiums, discounts and fair value adjustments, net			(34	)			(1	)
			3,845				1,872
Subsidiary Indebtedness:
ETP Debt
5.65% Senior Notes due August 1, 2012			—				400
6.0% Senior Notes due July 1, 2013			350				350
8.5% Senior Notes due April 15, 2014			292				350
5.95% Senior Notes due February 1, 2015			750				750
6.125% Senior Notes due February 15, 2017			400				400
6.7% Senior Notes due July 1, 2018			600				600
9.7% Senior Notes due March 15, 2019			400				600
9.0% Senior Notes due April 15, 2019			450				650
4.65% Senior Notes due June 1, 2021			800				800
5.20% Senior Notes due February 1, 2022			1,000				—
6.625% Senior Notes due October 15, 2036			400				400
7.5% Senior Notes due July 1, 2038			550				550
6.05% Senior Notes due June 1, 2041			700				700
6.5% Senior Notes due February 1, 2042			1,000				—
ETP $2.5 billion Revolving Credit Facility due October 27, 2016			1,395				314
Other			—				81
Unamortized premiums, discounts and fair value adjustments, net			(14	)			(2	)
			9,073				6,943
Panhandle Debt
6.05% Senior Notes due August 15, 2013			250				—
6.2% Senior Notes due November 1, 2017			300				—
7.0% Senior Notes due June 15, 2018			400				—
8.125% Senior Notes due June 1, 2019			150				—
7.0% Senior Notes due July 15, 2029			66				—
Term Loan due February 23, 2015			455				—
Unamortized premiums, discounts and fair value adjustments, net			136				—
			1,757				—
Regency Debt
9.375% Senior Notes due June 1, 2016			162				250
6.875% Senior Notes due December 1, 2018			600				600
6.5% Senior Notes due July 15, 2021			500				500
5.5% Senior Notes due April 15, 2023			700				—
Regency Revolving Credit Facility			192				332
Unamortized premiums, discounts and fair value adjustments, net			3				5
			2,157				1,687

 

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		December 31,
		2012				2011
Southern Union Debt
7.6% Senior Notes due February 1, 2024		$	360			$	—
8.25% Senior Notes due November 14, 2029			300				—
7.2% Junior Subordinated Notes due November 1, 2066			600				—
Southern Union Revolving Credit Facility			210				—
Other			7				—
Unamortized premiums, discounts and fair value adjustments, net			49				—
			1,526				—
Sunoco Debt
4.875% Senior Notes due October 15, 2014			250				—
9.625% Senior Notes due April 15, 2015			250				—
5.75% Senior Notes due January 15, 2017			400				—
9.00% Debentures due November 1, 2024			65				—
Other			25				—
Unamortized premiums, discounts and fair value adjustments, net			104				—
			1,094				—
Sunoco Logistics Debt
8.75% Senior Notes due February 15, 2014			175				—
6.125% Senior Notes due May 15, 2016			175				—
5.50% Senior Notes due February 15, 2020			250				—
4.65% Senior Notes due February 15, 2022			300				—
6.85% Senior Notes due February 15, 2040			250				—
6.10% Senior Notes due February 15, 2042			300				—
Sunoco Logistics $200 million Revolving Credit Facility due August 21, 2013			26				—
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015			20				—
Sunoco Logistics $350 million Revolving Credit Facility due August 22, 2016			93				—
Unamortized premiums, discounts and fair value adjustments, net			143				—
			1,732				—
Transwestern Debt
5.39% Senior Notes due November 17, 2014			88				88
5.54% Senior Notes due November 17, 2016			125				125
5.64% Senior Notes due May 24, 2017			82				82
5.36% Senior Notes due December 9, 2020			175				175
5.89% Senior Notes due May 24, 2022			150				150
5.66% Senior Notes due December 9, 2024			175				175
6.16% Senior Notes due May 24, 2037			75				75
Unamortized premiums, discounts and fair value adjustments, net			(1	)			(1	)
			869				869
			22,053				11,371
Current maturities			(613	)			(424	)
		$	21,440			$	10,947

 

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The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $386 million in unamortized premiums and fair value adjustments, net:

 

2013		$	613
2014			1,003
2015			1,540
2016			2,073
2017			3,184
Thereafter			13,254
Total		$	21,667

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

ETP as Co-Obligor of Sunoco Debt

In connection with the Sunoco Merger and Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco’s existing senior notes and debentures.

Senior Notes

ETE Senior Notes

We used the net proceeds from our Senior Secured Term Loan, along with proceeds received from ETP in the Citrus Acquisition, to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes.

Borrowings bear interest at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of December 31, 2012 was 3.75%.

The ETE Senior Notes are unsecured obligations of ETE and the obligation to repay the ETE Senior Notes is not guaranteed by any of ETE’s subsidiaries, including ETP, Regency, and their respective subsidiaries. The indebtedness of ETP and Regency and their respective subsidiaries effectively ranks senior to the ETE Senior Notes.

Southern Union Junior Subordinated Notes

Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.32% at December 31, 2012.

Panhandle Term Loans

In February 2012, Southern Union refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 23, 2015, with LNG Holdings as borrower and PEPL and

 

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Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt. The effective interest rate of PEPL’s term loan was 1.84% at December 31, 2012.

Bridge Term Loan Facility

Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated the 364-day Bridge Term Loan Facility. For the year ended December 31, 2012, bridge loan related fees reflects the recognition of $62 million of commitment fees upon termination of the facility.

ETP Senior Notes

The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us or any of ETP’s subsidiaries. The ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries. The balance is payable upon maturity. Interest on the ETP Senior Notes is paid semi-annually.

January 2013 Senior Notes Offering

In January 2013, ETP completed a public offering of $800 million aggregate principal amount of our 3.6% Senior Notes due February 1, 2023 and $450 million aggregate principal amount of its 5.15% Senior Notes due February 1, 2043. ETP used the net proceeds of approximately $1.24 billion from this offering to repay borrowings outstanding under its revolving credit facility and for general partnership purposes.

In addition, in January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes and $350 million of 4.95% Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under Sunoco Logistics’ existing Senior Notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 million and $200 million Sunoco Logistics Credit Facilities and for general partnership purposes.

Transwestern Senior Notes

The Transwestern Pipeline Company, LLC (“Transwestern”) notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.

Regency Senior Notes

The Regency Senior Notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency Senior Notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency Senior Notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.

Revolving Credit Facilities

ETE Senior Secured Credit Facility

The Parent Company has a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. Under the Parent Company Credit Agreement, the obligations of ETE are secured by all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) its ownership of ETP Common Units; (ii) ETE’s equity interest in ETP LLC and ETP GP, through which ETE holds the IDRs in ETP; (iii) the Common Units of Regency; and (iv) ETE’s equity interest in Regency GP LLC and Regency GP LP, through which ETE holds the IDRs in Regency.

 

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Borrowings bear interest, at ETE’s option, at either the Eurodollar rate plus an applicable margin or the alternative base rate. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are based upon ETE’s leverage ratio and range from 2.75% to 3.75% for Eurodollar loans and from 1.75% to 2.75% for base rate loans. The commitment fee payable on the unused portion of the Parent Company Credit Agreement is based on ETE’s leverage ratio and ranges from 0.50% to 0.75%.

In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.

As of December 31, 2012, we had a balance of $60 million outstanding under the Parent Company Credit Agreement and the amount available for future borrowings was $140 million. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 4.06%.

ETP Credit Facility

The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt.

On October 27, 2011, ETP amended and restated the ETP Credit Facility to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on our current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.

ETP used approximately $2.0 billion of Sunoco’s cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings under the ETP Credit Facility.

As of December 31, 2012, ETP had a balance of $1.40 billion outstanding under the ETP Credit Facility and, taking into account letters of credit of approximately $72 million, $1.03 billion available for future borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.71%.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $1.15 billion, with $200 million of availability for letters of credit that matures June 15, 2014. As of December 31, 2012, Regency had a balance of $192 million outstanding under the Regency Credit Facility in revolving credit loans and approximately $12 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2012, which is reduced by any letters of credit, was approximately $946 million. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 2.93%.

The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans will be

 

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calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.0%. The applicable margin ranges from 1.50% to 2.25% for base rate loans and 2.50% to 3.25% for Eurodollar loans.

Regency pays (i) a commitment fee ranging between 0.375% and 0.50% per annum for the unused portion of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 2.50% and 3.25% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of its letter of credit exposure. In December 2011, Regency amended its credit facility to allow for additional investments in its joint ventures.

Southern Union Credit Facility

The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union’s senior unsecured notes. The weighted average interest rate on the total amount outstanding as of December 31, 2012 was 1.84%.

On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility. The amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund the Partnership’s working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under $350 million Credit Facility and $200 million Credit Facility were $93 million and $26 million, respectively, at December 31, 2012.

In May 2012, Sunoco Logistics’ West Texas Gulf entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Outstanding borrowings under this credit facility were $20 million at December 31, 2012.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Parent Company Credit Agreement contains customary representations, warranties and covenants, including financial covenants regarding a maximum leverage ratio, a maximum consolidated leverage ratio, a minimum fixed charge coverage ratio and a minimum loan to value ratio. In addition, the Parent Company Credit Agreement contains customary events of default, including, but not limited to, (i) default for failure to pay the principal on any loan or any reimbursement obligation with respect to any letter of credit when due and payable, (ii) failure to duly observe, perform or comply with certain specified covenants, (iii) a representation or warranty made in connection with any loan document proves to have been false or incorrect in any material respect on any date on or as of which made, and (iv) the occurrence of a change of control.

 

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The Parent Company Senior Secured Revolving Credit Facility contains financial covenants as follows:

 

•

Maximum Leverage Ratio—Consolidated Funded Debt of the Parent Company (as defined) to Consolidated EBITDA (as defined in the agreements) of the Parent Company of not more than 4.5 to 1, with a permitted increase to 5 to 1 during a specified acquisition period extending for two fiscal quarters following the close of a specified acquisition;

 

•

Maximum Consolidated Leverage Ratio—Consolidated Funded Debt of the Parent Company, ETP and Regency to Consolidated EBITDA of ETP and Regency of not more than 5.5 to 1;

 

•

Fixed Charge Coverage Ratio of not less than 3 to 1; and

 

•

Value to Loan Ratio of not less than 2 to 1.

Covenants Related to ETP

The agreements relating to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the ETP’s and certain of the ETP’s subsidiaries’ ability to, among other things:

 

•

incur indebtedness;

 

•

grant liens;

 

•

enter into mergers;

 

•

dispose of assets;

 

•

make certain investments;

 

•

make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);

 

•

engage in business substantially different in nature than the business currently conducted by ETP and its subsidiaries;

 

•

engage in transactions with affiliates; and

 

•

enter into restrictive agreements.

The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Covenants Related to Regency

The Regency Senior Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to:

 

•

incur additional indebtedness;

 

•

pay distributions on, or repurchase or redeem equity interests;

 

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•

make certain investments;

 

•

incur liens;

 

•

enter into certain types of transactions with affiliates; and

 

•

sell assets, consolidate or merge with or into other companies.

If the Regency Senior Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants. The Regency Credit Facility contains the following financial covenants:

 

•

Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.25 to 1.

 

•

Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.75 to 1.

 

•

Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3 to 1.

The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:

 

•

incur indebtedness;

 

•

grant liens;

 

•

enter into sale and leaseback transactions;

 

•

make certain investments, loans and advances;

 

•

dissolve or enter into a merger or consolidation;

 

•

enter into asset sales or make acquisitions;

 

•

enter into transactions with affiliates;

 

•

prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);

 

•

issue capital stock or create subsidiaries; or

 

•

engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.

Covenants Related to Southern Union

Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Financial covenants exist in certain of the Southern Union’s debt agreements. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these

 

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covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the financial covenants are as follows:

 

•

Under the Southern Union Credit Facility, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, cannot exceed 5.25 times through December 31, 2012 and 5.00 times thereafter;

 

•

Under the Southern Union Credit Facility, in the event Southern Union’s credit rating falls below investment grade, the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated interest expense, as defined therein, cannot be less than 2.00 times;

 

•

Under LNG Holding’s $455 million term loan, the ratio of consolidated funded debt to consolidated earnings before interest, taxes, depreciation and amortization, as defined therein, for Panhandle cannot exceed 5.00 times.

In addition to the above financial covenants, Southern Union and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.

Covenants Related to Sunoco Logistics

Sunoco Logistics’ $350 and $200 million Credit Facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit Sunoco Logistics, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period.

Sunoco Logistics’ $35 million Credit Facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2012 shall not be less than 1.00 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1.

Compliance With Our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2012.

7.    REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions as discussed in Note 3, ETE issued 3,000,000 Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of

 

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$300 million and are reflected as long-term liabilities in our consolidated balance sheets as of December 31, 2012 and 2011. The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Partnership Agreement that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million as of December 31, 2012. During 2011, we recorded non-cash charges of approximately $5 million to increase the carrying value of the Preferred Units to the estimated fair value of $323 million as of December 31, 2011.

Preferred Units of Subsidiary

Regency had 4,371,586 Regency Preferred Units outstanding at December 31, 2012, which were convertible into 4,658,700 Regency Common Units. If outstanding on September 2, 2029 the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s partnership agreement.

The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:

 

		Regency Preferred Units				Amount
Balance, December 31, 2011			4,371,586			$	71
Accretion to redemption value			—				2
Balance, December 31, 2012			4,371,586			$	73

8.    EQUITY:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its

 

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affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2012, there were issued and outstanding 279,955,608 Common Units representing an aggregate 99.75% limited partner interest in the Partnership.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units

The change in ETE Common Units during the years ended December 31, 2012, 2011 and 2010 was as follows:

 

		Years Ended December 31,
		2012				2011				2010
Number of Common Units, beginning of period			222,972,708				222,941,172				222,898,248
Issuance of restricted Common Units under long-term incentive plan			740				31,536				42,924
Issuance of common units in connection with Southern Union Merger (See Note 3)			56,982,160				—				—
Number of Common Units, end of period			279,955,608				222,972,708				222,941,172

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Regency and the underlying book value arising from issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction. If ETP or Regency issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the periods presented.

As a result of ETP’s and Regency’s issuances and redemptions of Common Units, we have recognized increases in partners’ capital of $80 million, $153 million and $352 million for the years ended December 31, 2012, 2011 and 2010, respectively.

 

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Sale of Common Units by ETP

The following table summarizes ETP’s public offerings of ETP Common Units during the periods presented:

 

Date		Number of ETP Common Units(1)				Price per ETP Unit				Net Proceeds				Use of Proceeds
January 2010			9,775,000			$	44.72			$	424				(2	)(3)
August 2010			10,925,000				46.22				489				(2	)(3)
April 2011			14,202,500				50.52				695				(3	)
November 2011			15,237,500				44.67				660				(2	)(3)
July 2012			15,525,000				44.57				671				(2)(3)

 

(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.

(2)	Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

ETP issued 90,706,000 ETP Class F Units in connection with the Holdco Transaction that are reported as treasury units, which are entitled to receive distributions in accordance with their terms, see Note 3.

ETP’s Equity Distribution Program

From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.

In January 2013, ETP entered into an equity distribution agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“BofA Merrill Lynch”). According to the provisions of this agreement, ETP may offer and sell from time to time through BofA Merrill Lynch, as its sales agent, ETP Common Units having an aggregate offering price of up to $200 million. Under the terms of this agreement, ETP may also sell ETP Common Units to BofA Merrill Lynch as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to BofA Merrill Lynch as principal would be pursuant to the terms of a separate agreement between us and BofA Merrill Lynch.

ETP’s Equity Incentive Plan Activity

As discussed in Note 9, ETP issues ETP Common Units to employees and directors upon vesting of awards grander under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

ETP’s Distribution Reinvestment Program

In April 2011, ETP filed a registration statement with the SEC covering its DRIP. The DRIP provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. The registration statement covers the issuance of up to 5,750,000 Common Units under the DRIP.

During 2012, distributions of approximately $43 million were reinvested under the DRIP resulting in the issuance of 1,038,825 ETP Common Units.

 

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Sale of Common Units by Regency

The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:

 

Date		Number of Regency Common Units(1)				Price per Regency Unit				Net Proceeds				Use of Proceeds
August 2010			17,537,500			$	23.80			$	400				(2	)
May 2011			8,500,001				(4	)			204				(3	)
October 2011			11,500,000				20.92				232				(2	)
March 2012			12,650,000				24.47				297				(2	)(3)

 

(1)	Number of Common Units includes the exercise of the overallotment options by the underwriters.

(2)	Proceeds were used to repay amounts outstanding under the Regency Credit Facility.

(3)	Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

(4)	Regency Units were issued in a private placement.

On June 19, 2012, Regency entered into an Equity Distribution Agreement with Citi under which Regency may offer and sell Regency Common Units, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. Sales of these units, if any, made under the Regency Equity Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and Citi. Under the terms of this agreement, Regency may also sell Regency Common Units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of Regency Common Units to Citi as principal would be pursuant to the terms of a separate agreement between Regency and Citi. Regency intends to use the net proceeds from the sale of these units for general partnership purposes. During the year ended December 31, 2012, Regency issued 691,129 Regency Common Units pursuant to its Equity Distribution Agreement with Citi and received net proceeds of $15 million.

Contributions to Subsidiaries

The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. In order to maintain its general partner interest in ETP, ETP GP was previously required to make contributions to ETP each time ETP issued limited partner interests for cash or in connection with acquisitions. These contributions were generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP.

The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP. Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest. Regency GP’s interest in Regency’s distributions is reduced if Regency issues additional units and Regency GP does not contribute a proportionate amount of capital to Regency to maintain its General Partner interest.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partner interests, including IDRs, and distributions related to its 60% interest in Holdco. We currently have no independent operations outside of our direct and indirect interests in ETP, Regency and Holdco.

 

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Our distributions declared during the years ended December 31, 2012, 2011 and 2010 are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per ETE Common Unit
September 30, 2012		November 6, 2012		November 16, 2012		$	0.6250
June 30, 2012		August 6, 2012		August 17, 2012			0.6250
March 31, 2012		May 4, 2012		May 18, 2012			0.6250
December 31, 2011		February 7, 2012		February 17, 2012			0.6250
September 30, 2011		November 4, 2011		November 18, 2011		$	0.6250
June 30, 2011		August 5, 2011		August 19, 2011			0.6250
March 31, 2011		May 6, 2011		May 19, 2011			0.5600
December 31, 2010		February 7, 2011		February 18, 2011			0.5400
September 30, 2010		November 8, 2010		November 19, 2010		$	0.5400
June 30, 2010		August 9, 2010		August 19, 2010			0.5400
March 31, 2010		May 7, 2010		May 19, 2010			0.5400
December 31, 2009		February 8, 2010		February 19, 2010			0.5400

On January 28, 2013, the Parent Company declared a cash distribution for the three months ended December 31, 2012 of $0.635 per Common Unit, or $2.54 annualized. We paid this distribution on February 19, 2013 to Unitholders of record at the close of business on February 7, 2013.

ETP’s Quarterly Distribution of Available Cash

ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.

ETP’s distributions declared during the periods presented below are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per ETP Common Unit
September 30, 2012		November 6, 2012		November 14, 2012		$	0.89375
June 30, 2012		August 6, 2012		August 14, 2012			0.89375
March 31, 2012		May 4, 2012		May 15, 2012			0.89375
December 31, 2011		February 7, 2012		February 14, 2012			0.89375
September 30, 2011		November 4, 2011		November 14, 2011		$	0.89375
June 30, 2011		August 5, 2011		August 15, 2011			0.89375
March 31, 2011		May 6, 2011		May 16, 2011			0.89375
December 31, 2010		February 7, 2011		February 14, 2011			0.89375
September 30, 2010		November 8, 2010		November 15, 2010		$	0.89375
June 30, 2010		August 9, 2010		August 16, 2010			0.89375
March 31, 2010		May 7, 2010		May 17, 2010			0.89375
December 31, 2009		February 8, 2010		February 15, 2010			0.89375

 

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On January 28, 2013, ETP declared a cash distribution for the three months ended December 31, 2012 of $0.89375 per ETP Common Unit, or $3.575 annualized. ETP paid this distribution on February 14, 2013 to ETP Unitholders of record at the close of business on February 7, 2013.

Regency’s Quarterly Distribution of Available Cash

Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General Partner within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.

Distributions paid by Regency since the date of acquisition are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Regency  Common Unit
September 30, 2012		November 6, 2012		November 14, 2012		$	0.460
June 30, 2012		August 6, 2012		August 14, 2012			0.460
March 31, 2012		May 7, 2012		May 14, 2012			0.460
December 31, 2011		February 6, 2012		February 13, 2012			0.460
September 30, 2011		November 7, 2011		November 14, 2011		$	0.455
June 30, 2011		August 5, 2011		August 12, 2011			0.450
March 31, 2011		May 6, 2011		May 13, 2011			0.445
December 31, 2010		February 7, 2011		February 14, 2011			0.445
September 30, 2010		November 5, 2010		November 12, 2010		$	0.445
June 30, 2010		August 6, 2010		August 13, 2010			0.445

On January 28, 2013, Regency declared a cash distribution for the three months ended December 31, 2012 of $0.46 per Regency Common Unit, or $1.84 annualized. Regency paid this distribution on February 14, 2013 to Regency Unitholders of record at the close of business on February 7, 2013.

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of AOCI, net of tax:

 

		December 31,
		2012				2011
Net gains (losses) on commodity related hedges		$	(3	)		$	2
Actuarial loss related to pensions and other postretirement benefits			(10	)			—
Equity investments, net			(9	)			—
Subtotal			(22	)			2
Amounts attributable to noncontrolling interest			10				(1	)
Total AOCI included in partners’ capital, net of tax		$	(12	)		$	1

 

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The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:

 

		December 31,
		2012				2011
Net gains on commodity related hedges		$	2			$	—
Actuarial loss relating to pension and other postretirement benefits			5				—
Total		$	7			$	—

9.    UNIT-BASED COMPENSATION PLANS:

We, ETP, Sunoco Logistics and Regency have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units. As of December 31, 2012, 2,852,936 units remain available to be awarded under the plan.

During 2012, no awards were granted to ETE employees and 740 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.

During 2012, a total of 28,325 ETE units vested, with a total fair value of $1 million as of the vesting date. As of December 31, 2012, a total of 54,972 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of $1 million in compensation over a weighted average period of 1.9 years.

ETP Unit-Based Compensation Plans

Unit Grants

ETP has granted restricted unit awards to employees that vest over a specified time period, typically a five-year period at 20% per year, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.”

Under ETP’s equity incentive plans, its non-employee directors each receive grants that vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.

 

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Award Activity

The following table shows the activity of the ETP awards granted to employees and non-employee directors:

 

		Number of ETP Units				Weighted Average Grant-Date Fair Value Per ETP Unit
Unvested awards as of December 31, 2011			2,563,709			$	46.37
Awards granted			289,930				43.93
Awards vested			(647,498	)			44.58
Awards forfeited			(346,982	)			44.58
Unvested awards as of December 31, 2012			1,859,159				46.95

During the years ended December 31, 2012, 2011 and 2010, the weighted average grant-date fair value per unit award granted was $43.93, $48.35 and $49.82, respectively. The total fair value of awards vested was $29 million, $27 million and $17 million, respectively based on the market price of ETP Common Units as of the vesting date. As of December 31, 2012, a total of 1,859,159 unit awards remain unvested, for which ETP expects to recognize a total of $51 million in compensation expense over a weighted average period of 1.8 years.

Sunoco Logistics Unit-Based Compensation Plan

Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.9 million Sunoco common units. As of December 31, 2012, a total of 427,610 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $10 million of expense over a weighted-average period of 2.5 years.

Related Party Awards

McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by an ETE officer, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such ETE officer. These rights include the economic benefits of ownership of these ETE units based on a five-year vesting schedule whereby the ETP officers will vest in the ETE units at a rate of 20% per year. As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. As these units were outstanding prior to these awards, these awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE.

ETP is recognizing non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded to the ETP employees assuming no forfeitures. For the years ended December 31, 2012, 2011 and 2010, ETP recognized non-cash compensation expense, net of forfeitures, of $1 million, $2 million and $4 million, respectively, as a result of these awards. As of December 31, 2012, rights related to 90,000 ETE common units remain outstanding, for which ETP expects to recognize a total of less than $1 million in compensation expense over a weighted average period of 0.6 years.

Regency Unit-Based Compensation Plans

Regency has the following awards outstanding as of December 31, 2012:

 

•

156,550 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $21.96 per unit option;

 

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•

no Regency restricted (non-vested) Common Units; and

 

•

1,226,542 Regency Phantom Units, with a weighted average grant date fair value of $23.22 per Phantom Unit.

In conjunction with the Regency Transactions, certain of Regency’s then-outstanding Phantom Units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards. Each of Regency’s outstanding Phantom Units as of December 31, 2012 is the economic equivalent of one Regency Common Unit and is accompanied by a distribution equivalent right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units. The outstanding Regency Phantom Units will vest one-third on each March 15th through 2013.

Regency expects to recognize $26 million of compensation expense related to the Regency Phantom Units over a weighted average period of five years.

10.    INCOME TAXES:

As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

 

		Years Ended December 31,
		2012				2011				2010
Current expense (benefit):
Federal		$	(3	)		$	(1	)		$	1
State			6				17				9
Total			3				16				10
Deferred expense:
Federal			41				—				3
State			10				1				1
Total			51				1				4
Total income tax expense from continuing operations		$	54			$	17			$	14

Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the year ended December 31, 2012 is a as follows:

 

		Holdco(1)				Other Corporate Subsidiaries(2)				Partnership(3)				Consolidated
Income tax expense (benefit) at U.S. statutory rate of 35%		$	(1	)		$	(3	)		$	—			$	(4	)
Increase (reduction) in income taxes resulting from:
Nondeductible executive compensation			28				—				—				28
State income taxes (net of federal income tax effects)			9				—				2				11
Other			17				2				—				19
Income Tax from continuing operations		$	53			$	(1	)		$	2			$	54

 

(1)	Holdco, which was formed via the Sunoco Merger and the Holdco transactions (see Note 3), includes Sunoco and Southern Union and their subsidiaries.

 

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(2)	Includes Oasis Pipeline Company, Pueblo Holdings Inc. (Pueblo), Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. The latter three entities were acquired in the Sunoco transaction.

(3)	Includes Energy Transfer Equity, L.P. and its subsidiaries that are classified as pass-through entities for federal income tax purposes.

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

 

		December 31,
		2012				2011
Deferred tax assets:
Net operating losses and alternative minimum tax credit		$	270			$	4
Pension and other postretirement benefits			127				—
Long term debt			117				—
Other			290				4
Total deferred income tax assets			804				8
Valuation allowance			(94	)			(3	)
Net deferred income tax assets			710				5
Deferred income tax liabilities:
Properties, plants and equipment			(2,026	)			(147	)
Inventory			(516	)			—
Investments in unconsolidated affiliates			(1,543	)			(72	)
Trademarks			(192	)			—
Other			(129	)			—
Total deferred income tax liabilities			(4,406	)			(219	)
Net deferred income tax liability			(3,696	)			(214	)
Less: current portion of deferred income tax asset (liabilities)			(130	)			3
Accumulated deferred income taxes		$	(3,566	)		$	(217	)

The completion of the Southern Union, Sunoco and Holdco transactions (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:

 

		December 31, 2012
Net deferred income tax liability, beginning of year		$	(214	)
Southern Union acquisition			(1,428	)
Sunoco acquisition			(1,989	)
Tax provision (including discontinued operations)			(62	)
Other			(3	)
Net deferred income tax liability		$	(3,696	)

Holdco and other corporate subsidiaries have gross federal net operating loss carryforwards of $368 million, of which $1 million, $3 million, $18 million, $40 million and $306 million will expire in 2028, 2029, 2030, 2031 and 2032, respectively. Holdco has $37 million of federal alternative minimum tax credit which do not expire. Holdco and other corporate subsidiaries have state net operating loss carryforward benefits of $104 million, net of federal tax which expire between 2013 and 2032. The valuation allowance is applicable to the federal net operating loss benefits and state net operating loss benefits of $4 million and $90 million, respectively. The

 

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valuation allowance of $90 million for state net operating loss benefits is applicable to Sunoco pre-acquisition periods. The valuation for federal net operating loss benefits increased $1 million in 2012.

The following table sets forth the changes in unrecognized tax benefits:

 

		Years Ended December 31,
		2012				2011				2010
Balance at beginning of year		$	2			$	2			$	1
Additions attributable to acquisitions			28				—				—
Additions attributable to tax positions taken in the current year			—				1				—
Additions attributable to tax positions taken in prior years			—				—				1
Lapse of statute			(3	)			(1	)			—
Balance at end of year		$	27			$	2			$	2

As of December 31, 2012, we have $24 million ($16 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $5 million ($3 million, net of federal tax) within the next 12 months due to settlement of certain positions.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2012, we recognized interest and penalties of less than $1 million. At December 31, 2012, we have interest and penalties accrued of $5 million, net of tax.

In general, ETE and its subsidiaries are no longer subject to examination by the Internal Revenue Service for tax years prior to 2009, except Sunoco, Regency and Pueblo which are no longer subject to examination by the IRS for tax years prior to 2007 and Southern Union which is no longer subject to examination by the IRS for tax years prior to and 2004.

Sunoco has been examined by the IRS for the 2007 and 2008 tax years, however, the statutes remain open for both of these tax years due to carryback of net operating losses. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2012, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We will vigorously defend and believe Southern Union’s tax position will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to this tax position. Regency and Pueblo are also under examination by the IRS for the 2007 and 2008 and the 2007 to 2009 tax years, respectively. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency and Pueblo will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. Neither of the proposed adjustments with respect to Regency or Pueblo would have a material impact upon our financial statements.

ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

 

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11.    REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

Southern Union and its Subsidiaries

The FERC is currently conducting an audit of PEPL, a subsidiary of Southern Union, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

Contingent Residual Support Agreement—AmeriGas

In order to finance the cash portion of the purchase price of the Propane Transaction described in Note 3, AmeriGas Finance LLC (”Finance Company”), a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes (the “Supported Debt”).

In connection with the closing of the Propane Transaction, ETP entered into and delivered a Contingent Residual Support Agreement (”CRSA”) with AmeriGas, Finance Company, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt as defined in the CRSA.

Commitments

In the normal course of business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $60 million, $29 million and $24 million for the years ended December 31, 2012, 2011 and 2010, respectively, which include contingent rentals totaling $6 million in 2012. During the three months ended December 31, 2012, approximately $4 million of rental expense was recovered through related sublease rental income.

Future minimum lease commitments for such leases are:

 

Years Ending December 31:
2013		$	92
2014			82
2015			79
2016			64
2017			52
Thereafter			462
Future minimum lease commitments			831
Less: Sublease rental income			(64	)
Net future minimum lease commitments		$	767

 

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Amounts reflected above do not include future minimum lease commitments for the Southern Union’s distribution operations, which were reclassified and reported as assets and liabilities held for sale at December 31, 2012 as described in Note 3.

ETP and Regency’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2012 and 2011, accruals of approximately $15 million and $18 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.

No amounts have been recorded in our December 31, 2012 or 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Will Price. Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010. Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC. As a result, Southern Union believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs). In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case. Southern Union believes it has no liability associated with this proceeding.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General filed a regulatory complaint with the MDPU against New England Gas

 

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Company with respect to certain environmental cost recoveries. The Attorney General is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the Attorney General requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s Vice Chairman, President and COO, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the Attorney General contends only would qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses. Additionally, New England Gas Company’s assets and liabilities have been included in discontinued operations at December 31, 2012.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.

Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the New Mexico Environmental Department concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The New Mexico Environmental Department has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $1 million and at Jal #3 in the amount of $7 million. Hearings on the compliance orders were delayed until May 2013 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the New Mexico Environmental Department claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

FGT Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGT’s mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $83 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGT’s pipeline without the consent of FGT although FGT would be required to relocate the pipeline if it did not provide such consent. While FGT would seek reimbursement of any costs associated with relocation of its pipeline in connection with an FDOT project, FGT may not be successful in obtaining such reimbursement and, as such, could be required to bear the cost of such relocation. In any such instance, FGT would seek recovery of the reimbursement costs in rates. The judge also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. On June 6, 2012, Florida’s Fourth District Court of Appeal (“4th DCA”) issued an opinion affirming the jury award of damages and also affirming or remanding for further consideration by the trial court certain other determinations with respect to FGT’s easement rights and FDOT/FTE’s obligations regarding future FDOT/FTE projects. In particular, the 4th DCA affirmed that FDOT/FTE could not pave directly over our pipeline without FBT’s consent and remanded and directed the trial court to make reference in the final judgment to FDOT/FTE’s obligation to seek reasonable alternatives to relocation. The 4th DCA did overturn the portion of the trial court judgment defining the width of FGT’s

 

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easements as 15 feet on either side of its pipelines and defining the temporary work space available to Florida Gas under its easements as 75 feet in width, stating that the width of such easements and temporary work space should be determined on a case by case basis dependent on the needs of each particular relocation and whether a road improvement is a material interference with the easement. Reimbursement for any future relocation expenses will also be determined on a case by case basis. As a result of the decision by the 4th DCA affirming the monetary award of the judgment and the trial court’s November 7, 2012 issuance of a peremptory writ of mandamus, FDOT paid to FGT on November 16, 2012 the sum of $100 million, representing the amount of judgment plus interest through that date. The amounts received reduced FGTs’ property, plant and equipment costs. FGT previously filed a petition requesting the Supreme Court of Florida to exercise its discretionary jurisdiction and to reverse the portion of the 4th DCA decision overturning the trial court judgment specifically defining the width of FGTs’ easements and temporary work space. By order dated December 28, 2012, the Supreme Court of Florida denied that petition.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

The Texas case remains pending, and discovery is ongoing.

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern

 

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Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The deadline for the remaining defendants to file an answer or otherwise respond is March 1, 2013. Trial in this action is not currently set.

CrossCountry, a “Principal” under the Citrus capital stock agreement, filed a complaint in the Delaware Court of Chancery against El Paso Citrus Holdings, Inc. (“EPCH”) and its parent El Paso Corp. (“El Paso”) seeking a declaratory judgment that the Citrus Acquisition does not, as El Paso contended, trigger any provisions of the capital stock agreement that would require Southern Union to provide El Paso a right of first refusal (ROFR) concerning Citrus. The complaint was filed by CrossCountry following an exchange of letters between El Paso and Southern Union regarding the terms of the capital stock agreement. Following the filing of the declaratory judgment action, El Paso filed a third-party complaint against Southern Union, ETE, and ETP alleging, among other things, breach the capital stock agreement. El Paso was not seeking to enjoin the closing of the Citrus Acquisition, but rather sought a rescission of the Citrus Acquisition after it was completed or, alternatively, damages. All parties have agreed the Citrus Acquisition did not trigger a ROFR and the courts granted El Paso’s dismissal of its claims for rescission or damages with prejudice on April 20, 2012.

Litigation Related to Sunoco Merger

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 is pending approval by the state court.

MTBE Litigation

Sunoco, along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases are seeking to recover compensatory damages, and in some cases, injunctive relief, punitive damages and attorneys’ fees.

As of December 31, 2012, Sunoco was a defendant in two lawsuits involving one state and Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. Both cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.

 

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Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate liability of Sunoco in these matters; however, it is reasonably possible that a loss may be realized. Management believes that the MBTE cases could have a significant impact on results of operations for any future period, but does not believe that the cases will have a material adverse effect on its consolidated financial position.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities. We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Our subsidiaries have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage and to limit the financial liability which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our subsidiaries’ liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require some of our subsidiaries to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule is required by October 2013.

 

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On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require some of our subsidiaries to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes our subsidiaries might make in the future, but we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations.

On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. ETP is reviewing the new standards to determine the impact on its operations.

Our subsidiaries’ 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. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause our subsidiaries to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

 

•

Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.

 

•

Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

 

•

Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to MGPs and may also be responsible for the removal of old MGP structures.

 

•

Currently operating Sunoco retail sites.

 

•

Legacy sites related to Sunoco, that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites.

 

•

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2012, Sunoco had been named as a PRP at 35 identified or potentially identifiable as “Superfund” sites under federal and/or

 

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comparable state law. The Company is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

 

		December 31, 2012				December 31, 2011
Current		$	46			$	4
Non-current			166				10
Total environmental liabilities		$	212			$	14

During the year ended December 31, 2012 the Partnership had $12 million of expenditures related to environmental cleanup programs.

12.    PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by segment.

Investment in ETP

ETP injects and hold natural gas in our Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the

 

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spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream operations whereby the Company generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use derivative swap contracts to hedge forecasted sales of NGL equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

Derivatives are utilized in our midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices.

Prior to the deconsolidation of the Propane Business, we also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts. Prior to the sale of our cylinder exchange business, we used propane futures contracts to secure the purchase price of our propane inventory for a percentage of the anticipated sales.

 

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The following table details ETP’s outstanding commodity-related derivatives:

 

		December 31, 2012						December 31, 2011
		Notional Volume				Maturity		Notional Volume				Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX(1)			(30,980,000	)		2013-2014			(151,260,000	)		2012-2013
Power (Megawatt):
Forwards			19,650			2013			—			—
Futures			(1,509,300	)		2013			—			—
Options—Calls			1,656,400			2013			—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX			150,000			2013			(61,420,000	)		2012-2013
Swing Swaps IFERC			(83,292,500	)		2013			92,370,000			2012-2013
Fixed Swaps/Futures			27,077,500			2013			797,500			2012
Forward Physical Contracts			11,689,855			2013-2014			(10,672,028	)		2012
Options—Puts			—			2013			—			—
NGLs (Bbls):
Forwards/Swaps			(30,000	)		2013			—			—
Refined Products (Bbls)			(666,000	)		2013			—			—
Propane (Gallons):
Forwards/Swaps			—			—			38,766,000			2012-2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX			(18,655,000	)		2013			(28,752,500	)		2012
Fixed Swaps/Futures			(44,272,500	)		2013			(45,822,500	)		2012
Hedged Item—Inventory			44,272,500			2013			45,822,500			2012
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures			(8,212,500	)		2013			—			—
Options—Puts			—			—			3,600,000			2012
Options—Calls			—			—			(3,600,000	)		2012
NGLs (Bbls):
Forwards/Swaps			(930,000	)		2013			—			—
Refined Products (Bbls)			(98,000	)		2013			—			—

 

(1)	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

We expect losses of $6 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Investment in Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market

 

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forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.

The following table details Regency’s outstanding commodity-related derivatives:

 

		December 31, 2012						December 31, 2011
		Notional Volume				Maturity		Notional Volume				Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures			8,395,000			2013-2014			—			—
Propane (Gallons):
Forwards/Swaps			3,318,000			2013			—			—
Natural Gas Liquids (Barrels):
Forwards/Swaps			243,000			2013-2014			—			—
Options—Puts			—			—			110,000			2012
WTI Crude Oil (Barrels):
Forwards/Swaps			356,000			2014			—			—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures			—			—			2,198,000			2012
Propane (Gallons):
Forwards/Swaps			—			—			11,802,000			2012-2013
Natural Gas Liquids (Barrels):
Forwards/Swaps			—			—			533,000			2012-2013
WTI Crude Oil (Barrels):
Forwards/Swaps			—			—			350,000			2012-2014

As of December 31, 2011 all of the Regency’s commodity swap contracts were accounted for as cash flow hedges, and the Regency’s put options were accounted for on mark-to-market basis. On January 1, 2012, Regency, for accounting purposes, de-designated its swap contracts and will account for these contracts using the mark-to-market method of accounting. Regency has less than $1 million in net hedging gains in AOCI, the majority of which will be amortized to earnings over the next 12 months.

 

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Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of December 31, 2012, none of which are designated as hedges for accounting purposes:

 

Notional Amount Outstanding

Entity

Term

Type(1)

December 31, 2012

December 31, 2011

ETE

March 2017

Pay a fixed rate of 1.25% and receive a floating rate

$

500

$

—

ETP

May 2012(2)

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350

ETP

August 2012(2)

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500

ETP

July 2013(2)

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400

300

ETP

July 2014(2)

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400

—

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600

500

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

—

250

Southern Union

November 2016

Pay a fixed rate of 2.913% and receive a floating rate

75

N/A

Southern Union

November 2021

Pay a fixed rate of 3.746% and receive a floating rate

450

N/A

 

(1)	Floating rates are based on 3-month LIBOR.

(2)	These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

As of December 31, 2012, Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66 million of realized losses on hedged interest rate swaps, ETE also paid $102 million to terminate non-hedged interest rate swaps. The $102 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $169 million, including realized losses on hedged and non-hedged swaps.

 

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Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single or multiple counterparties.

Our counterparties consist primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on financial our position or results of operations as a result of counterparty nonperformance.

ETP utilizes master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. ETP had net deposits with counterparties of $41 million and $66 million as of December 31, 2012 and 2011, respectively.

Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and enters into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments. The aggregate fair value of Southern Union’s derivative instruments with credit-risk-related contingent features that are in a net liability position at December 31, 2012 was $4 million, all of which were included in the disposal group held for sale liabilities and December 31, 2012.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2012 and 2011:

 

		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		2012				2011				2012				2011
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)		$	8			$	77			$	(10	)		$	(1	)
Commodity derivatives			—				5				—				(10	)
			8				82				(10	)			(11	)

 

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		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		2012				2011				2012				2011
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)		$	110			$	227			$	(116	)		$	(251	)
Commodity derivatives			40				1				(44	)			(5	)
Interest rate derivatives			55				36				(235	)			(118	)
Embedded derivatives in Regency Preferred Units			—				—				(25	)			(39	)
			205				264				(420	)			(413	)
Total derivatives		$	213			$	346			$	(430	)		$	(424	)

The commodity derivatives (margin deposits) are recorded in other current assets on our consolidated balance sheets. The remainder of the derivatives are recorded in price risk management assets or price risk management liabilities. As of December 31, 2012 commodity derivative assets of $1 million and commodity derivatives liabilities of $8 million were recorded as non-current assets held for sale and current liabilities held for sale in our consolidated balance sheet. In addition to the above derivatives, $7 million of option premiums included in price risk management liabilities as of December 31, 2012 will amortize in 2013.

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments for the periods presented:

 

		Change in Value Recognized in OCI on Derivatives (Effective Portion)
		Years Ended December 31,
		2012				2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	8			$	6			$	50
Interest rate derivatives			—				—				(30	)
Total		$	8			$	6			$	20

 

		Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)		Amount of Gain/(Loss) Reclassified from     AOCI into Income  (Effective Portion)
				Years Ended December 31,
				2012				2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives		Cost of products sold		$	14			$	19			$	37
Interest rate derivatives		Interest expense, net			—				—				(87	)
Total				$	14			$	19			$	(50	)

 

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		Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
				Years Ended December 31,
				2012				2011				2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives		Cost of products sold		$	54			$	34			$	16
Total				$	54			$	34			$	16

 

		Location of Gain/ (Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income on Derivatives
				Years Ended December 31,
				2012				2011				2010
Derivatives in cash flow hedging relationships:
Commodity derivatives—Trading		Cost of products sold		$	(7	)		$	(30	)		$	—
Commodity derivatives—Non-trading		Cost of products sold			26				9				4
Commodity derivatives—Non-trading		Deferred gas purchases			26				—				—
Interest rate derivatives		Losses on non-hedged interest rate derivatives			(19	)			(78	)			(52	)
Embedded derivatives		Other income (expense)			14				18				(8	)
Total				$	40			$	(81	)		$	(56	)

13.    RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings plans which collectively cover virtually all employees, including those of ETP and Regency. Employer matching contributions are calculated using a formula based on employee contributions. We have made matching contributions of $11 million, $14 million and $10 million to the 401(k) savings plan for the years ended December 31, 2012, 2011 and 2010, respectively.

Regency previously sponsored its own 401(k) plan. Effective January 1, 2011, Regency’s 401(k) plan merged with and into that of ETP. As a result of the Regency Transactions, Regency’s matching contributions that had not yet fully vested became fully vested effective immediately. Regency made matching contributions of $2 million to its own 401(k) savings plan for period from May 26, 2010 to December 31, 2010.

Southern Union sponsors a defined contribution savings plan (Savings Plan) that is available to all employees. Southern Union contributions to the Savings Plan during the period from Acquisition (March 26, 2012) to December 31, 2012 were $6 million.

In addition, the Southern Union makes employer contributions to separate accounts, referred to as Retirement Power Accounts, within the defined contribution plan. The contribution amounts are determined as a percentage of compensation and range from 3.5% to 12%. Southern Union contributions are generally 100% vested after five years of continuous service. Southern Union contributions to Retirement Power Accounts during the period from Acquisition (March 26, 2012) to December 31, 2012 were $2 million.

 

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Pension and Other Postretirement Benefit Plans

Southern Union

Southern Union has funded non-contributory defined benefit pension plans that cover substantially all employees of Southern Union’s distribution operations. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

The 2012 postretirement benefits expense for Southern Union reflects the impact of curtailment accounting as postretirement benefits for all active participants who did not meet certain criteria were eliminated. The Company previously had postretirement health care and life insurance plans that covered substantially all Distribution and Transportation and Storage division employees, as well as all Corporate employees. The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.

Sunoco

Sunoco has both funded and unfunded noncontributory defined benefit pension plans (see “defined benefit plans”). Sunoco also has plans which provide health care benefits for substantially all of its current retirees (“postretirement benefit plans”). The postretirement benefit plans are unfunded and the costs are shared by Sunoco and its retirees. Prior to the Sunoco Merger on October 5, 2012, pension benefits under Sunoco’s defined benefit plans were frozen for most of the participants in these plans at which time Sunoco instituted a discretionary profit-sharing contribution on behalf of these employees in its defined contribution plan. Postretirement medical benefits were also phased down or eliminated for all employees retiring after July 1, 2010. Sunoco has established a trust for its postretirement benefit liabilities by making a tax-deductible contribution of approximately $200 million and restructuring the retiree medical plan to eliminate Sunoco’s liability beyond this funded amount. The retiree medical plan change eliminated substantially all of Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

 

		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at acquisition date		$	1,257			$	359
Service cost			3				1
Interest cost			15				3
Amendments			—				17
Benefits paid, net			(71	)			(8	)
Curtailments			—				(80	)
Actuarial (gain)/loss and other			(9	)			4
Benefit obligation at end of period		$	1,195			$	296

 

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		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
Change in plan assets:
Fair value of plan assets at acquisition date		$	941			$	306
Return on plan assets and other			22				5
Employer contributions			14				9
Benefits paid, net			(71	)			(8	)
Fair value of plan assets at end of period		$	906			$	312
Amount underfunded (overfunded) at end of period		$	289			$	(16	)
Amounts recognized in the consolidated balance sheets consist of:
Noncurrent assets		$	—			$	59
Current liabilities			(15	)			(2	)
Noncurrent liabilities			(274	)			(41	)
		$	(289	)		$	16
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain		$	(1	)		$	(1	)
Prior service cost			—				16
		$	(1	)		$	15

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

 

		Pension Benefits				Other Postretirement Benefits
Projected benefit obligation		$	1,195				N/A
Accumulated benefit obligation			1,179			$	225
Fair value of plan assets			906				185

Components of Net Periodic Benefit Cost

 

		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost		$	3			$	1
Interest cost			15				3
Expected return on plan assets			(21	)			(5	)
Special termination benefits charge			2				—
Curtailment recognition(1)			—				(15	)
			(1	)			(16	)
Regulatory adjustment(2)			9				2
Net periodic benefit cost		$	8			$	(14	)

 

(1)

Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly,

 

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Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

(2)

In its distribution operations, Southern Union recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

 

		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
Discount rate			3.41	%			2.39	%
Rate of compensation increase			3.17	%			N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

 

		December 31, 2012
		Pension Benefits				Other Postretirement Benefits
Discount rate			2.37	%			2.43	%
Expected return on assets:
Tax exempt accounts			7.63	%			7.00	%
Taxable accounts			N/A				4.50	%
Rate of compensation increase			3.02	%			N/A

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union’s other postretirement benefit plans are shown in the table below:

 

		December 31, 2012
Health care cost trend rate assumed for next year			7.78	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)			5.32	%
Year that the rate reaches the ultimate trend rate			2018

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

 

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Plan Assets

For the Southern Union plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its pension plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 70%, fixed income of 15% to 35%, alternative assets of 10% to 35% and cash of 0% to 10%. To achieve diversity within its other postretirement plan asset portfolio, Southern Union has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of 0% to 10%.

The investment strategy of Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns, maintain a sufficient funded status of the plans and limit required contributions. Sunoco has targeted the following asset allocations: equity of 35%, fixed income of 55%, and private equity investments of 10%. Sunoco anticipates future shifts in targeted asset allocations from equity securities to fixed income securities if funding levels improve due to asset performance or Sunoco contributions.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

 

		Fair Value as of December 31, 2012				Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
						Level 1				Level 2				Level 3
Asset Category:
Cash and cash equivalents		$	25			$	25			$	—			$	—
Mutual funds(1)			516				—				433				83
Fixed income securities			354				—				354				—
Multi-strategy hedge funds(2)			11				—				11				—
Total		$	906			$	25			$	798			$	83

 

(1)	Primarily comprised of approximately 36% equities, 54% fixed income securities, and 10% in other investments as of December 31, 2012.

(2)

Primarily includes hedge funds that invest in multiple strategies, including relative value, opportunistic/macro, long/short equities, merger arbitrage/event driven, credit, and short selling strategies, to generate long-term capital appreciation through a portfolio having a diversified risk profile with relatively low volatility and a low correlation with traditional equity and fixed-income markets. These investments can generally be redeemed effective as of the last day of a calendar quarter at the net asset value per share of the investment with approximately 65 days prior written notice.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:

 

		Fair Value as of December 31, 2012				Fair Value Measurements at December 31, 2012 Using Fair Value Hierarchy
						Level 1				Level 2				Level 3
Asset Category:
Cash and Cash Equivalents		$	7			$	7			$	—			$	—
Mutual funds(1)			147				126				21				—
Fixed income securities			158				—				158				—
Total		$	312			$	133			$	179			$	—

 

(1)	Primarily comprised of approximately 19% equities, 74% fixed income securities, 4% cash, and 3% in other investments as of December 31, 2012.

 

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The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. See Note 2 for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.

Contributions

We expect to contribute approximately $18 million to pension plans and approximately $8 million to other postretirement plans in 2013. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Southern Union’s and Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

 

Years		Benefits				Other Postretirement Benefits (Gross, Before Medicare Part D)				Other Postretirement Benefits (Medicare Part D Subsidy Receipts)
2013		$	254			$	38			$	1
2014			105				34				1
2015			98				33				1
2016			87				32				1
2017			82				30				1
2018—2021			328				107				4

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

14.    RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

Transactions between ETE’s subsidiaries and Enterprise were previously considered to be related party transactions due to Enterprise’s ownership of a portion of ETE’s limited partner interests. During the years ended December 31, 2011 and 2010, subsidiaries of ETE recorded sales to Enterprise and $1.04 billion and $697 million, respectively, and purchases from Enterprise of $507 million and $444 million, respectively, all of which were related party transactions based on Enterprise’s interests in ETE at the time of the transactions.

In addition, subsidiaries of ETE recorded sales with affiliates of $189 million during the year ended December 31, 2012.

 

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15.    REPORTABLE SEGMENTS:

As a result of the Holdco Acquisition in April 2013, our reportable segments were re-evaluated and have been recast to reflect the following reportable segments:

 

•

Investment in ETP, including the consolidated operations of ETP.

 

•

Investment in Regency, including the consolidated operations of Regency.

 

•

Corporate and Other, including the following:

 

•

activities of the Parent Company; and

 

•

the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

The segment information included below for the investment in Regency has been restated to reflect Regency’s retrospective consolidation of SUGS beginning March 26, 2012. Regency’s acquisition of SUGS was a transaction between entities under common control; therefore, Regency accounted for it similar to a pooling of interests. Accordingly, amounts reflected below for Regency have been adjusted to reflect Regency’s retrospective consolidation of SUGS.

Revenues from intrastate transportation and storage operations are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from interstate transportation and storage operations are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from midstream operations are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from retail marketing operations are primarily reflected in retail marketing. Revenues from ETP’s investment in Sunoco Logistics are primarily reflected in crude sales. Revenues from our Investment in Regency are primarily reflected in natural gas sales, NGL sales, gathering, transportation and other fees.

We previously reported net income as a measure of segment performance. Due to the change in our reportable segments described above, the financial information available to our chief operating decision maker to assess the performance is now based on Segment Adjusted EBITDA. Therefore, we have accordingly revised our segment operating performance measure that we report. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

 

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		Years Ended December 31,
		2012				2011				2010
Revenues:
Investment in ETP:
Revenues from external customers		$	15,671			$	6,761			$	5,843
Intersegment revenues			31				38				—
			15,702				6,799				5,843
Investment in Regency:
Revenues from external customers			1,986				1,426				715
Intersegment revenues			14				8				1
			2,000				1,434				716
Adjustments and Eliminations:			(738	)			(43	)			(3	)
Total revenues		$	16,964			$	8,190			$	6,556
Costs of products sold:
Investment in ETP		$	12,266			$	4,175			$	3,591
Investment in Regency			1,387				1,013				504
Adjustments and Eliminations			(565	)			(19	)			7
Total costs of products sold		$	13,088			$	5,169			$	4,102
Depreciation and amortization:
Investment in ETP		$	656			$	405			$	317
Investment in Regency			252				169				76
Corporate and Other			14				12				13
Adjustments and Eliminations			(51	)			—				—
Total depreciation and amortization		$	871			$	586			$	406
		As of December 31,
		2012				2011				2010
Equity in earnings of unconsolidated affiliates:
Investment in ETP		$	142			$	26			$	12
Investment in Regency			105				120				54
Adjustments and Eliminations			(35	)			(29	)			(1	)
Total equity in earnings of unconsolidated affiliates		$	212			$	117			$	65

 

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		Years Ended December 31,
		2012				2011				2010
Segment Adjusted EBITDA:
Investment in ETP		$	2,744			$	1,781			$	1,541
Investment in Regency			525				422				218
Corporate and Other			(52	)			(29	)			(21	)
Adjustments and Eliminations(1)			(112	)			(43	)			—
Total			3,105				2,131				1,738
Depreciation and amortization			(871	)			(586	)			(406	)
Interest expense, net of interest capitalized			(1,018	)			(740	)			(625	)
Bridge loan related fees			(62	)			—				—
Gain on deconsolidation of Propane Business			1,057				—				—
Losses on non-hedged interest rate derivatives			(19	)			(78	)			(52	)
Non-cash unit-based compensation expense			(47	)			(42	)			(31	)
Unrealized gains (losses) on commodity risk management activities			10				7				(110	)
Losses on extinguishments of debt			(123	)			—				(16	)
LIFO valuation reserve			(75	)			—				—
Proportionate share of unconsolidated affiliates’ interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes			(435	)			(114	)			(71	)
Adjusted EBITDA related to discontinued operations			(99	)			(23	)			(19	)
Other, net			14				(7	)			(49	)
Income from continuing operations before income tax expense		$	1,437			$	548			$	359

 

		As of December 31,
		2012				2011				2010
Total assets:
Investment in ETP		$	43,230			$	15,519			$	12,450
Investment in Regency			8,123				5,568				4,770
Corporate and Other			707				470				469
Adjustments and Eliminations			(3,156	)			(660	)			(11	)
Total		$	48,904			$	20,897			$	17,678

 

		Years Ended December 31,
		2012				2011				2010
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP(1)		$	3,057			$	2,922			$	1,470
Investment in Regency(2)			560				411				2,068
Adjustments and Eliminations			(124	)			—				—
Total		$	3,493			$	3,333			$	3,538

 

(1)	The year ended December 31, 2011 includes $1.42 billion acquired in the LDH Acquisition.

(2)	The year ended December 31, 2010 includes $1.55 billion acquired in the Regency Transactions.

 

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		As of December 31,
		2012				2011				2010
Advances to and investments in affiliates:
Investment in ETP		$	3,502			$	201			$	9
Investment in Regency			2,214				1,925				1,351
Adjustments and Eliminations			(979	)			(629	)			—
Total		$	4,737			$	1,497			$	1,360

16.    QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. For 2011, ETP’s propane operations were seasonal due to weather conditions in their service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to commercial and industrial customers are less weather sensitive. ETP’s Energy Transfer Company (“ETC OLP”) business is also seasonal due to the operations of ET Fuel System and the HPL System. We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

 

		Quarters Ended
		March 31				June 30				September 30				December 31				Total Year
2012:
Revenues		$	1,669			$	1,875			$	2,107			$	11,313			$	16,964
Gross margin			654				916				876				1,430				3,876
Operating income			183				367				358				452				1,360
Net income			961				75				(34	)			272				1,274
Limited Partners’ interest in net income			166				53				35				48				302
Basic net income per limited partner unit		$	0.73			$	0.19			$	0.13			$	0.17			$	1.13
Diluted net income per limited partner unit		$	0.73			$	0.19			$	0.13			$	0.17			$	1.13
2011:
Revenues		$	1,977			$	1,963			$	2,084			$	2,166			$	8,190
Gross margin			778				703				736				804				3,021
Operating income			363				263				272				339				1,237
Net income			199				107				61				161				528
Limited Partners’ interest in net income			88				66				69				86				309
Basic net income per limited partner unit		$	0.40			$	0.30			$	0.31			$	0.38			$	1.39
Diluted net income per limited partner unit		$	0.40			$	0.30			$	0.31			$	0.38			$	1.38

 

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17.    SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

 

		December 31,
		2012				2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	9			$	18
Accounts receivable from related companies			11				1
Note receivable from affiliate			3				—
Other current assets			—				1
Total current assets			23				20
ADVANCES TO AND INVESTMENTS IN AFFILIATES			6,094				2,226
INTANGIBLE ASSETS, net			19				—
GOODWILL			9				—
OTHER NON-CURRENT ASSETS, net			222				50
Total assets		$	6,367			$	2,296
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	1			$	—
Accounts payable to related companies			15				12
Interest payable			48				35
Price risk management liabilities			5				—
Accrued and other current liabilities			1				1
Current maturities of long-term debt			4				—
Total current liabilities			74				48
LONG-TERM DEBT, less current maturities			3,840				1,872
PREFERRED UNITS			331				323
OTHER NON-CURRENT LIABILITIES			9				—
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner			—				—
Limited Partners—Common Unitholders (279,955,608 and 222,972,708 units authorized, issued and outstanding at December 31, 2012 and 2011, respectively)			2,125				52
Accumulated other comprehensive income (loss)			(12	)			1
Total partners’ capital			2,113				53
Total liabilities and partners’ capital		$	6,367			$	2,296

 

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STATEMENTS OF OPERATIONS

 

		Years Ended December 31,
		2012				2011				2010
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(53	)		$	(30	)		$	(22	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized			(235	)			(164	)			(168	)
Bridge loan related fees			(62	)			—				—
Equity in earnings of affiliates			666				509				456
Losses on non-hedged interest rate derivatives			(15	)			—				(53	)
Other, net			(4	)			(5	)			(20	)
INCOME BEFORE INCOME TAXES			297				310				193
Income tax benefit			(7	)			—				—
NET INCOME			304				310				193
GENERAL PARTNER’S INTEREST IN NET INCOME			2				1				1
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	302			$	309			$	192

 

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STATEMENTS OF CASH FLOWS

 

		Years Ended December 31,
		2012				2011				2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	555			$	469			$	317
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions			(1,113	)			—				—
Contributions to affiliates			(487	)			—				—
Note receivable from affiliate			(221	)			—				—
Payments received on note receivable from affiliate			55				—				—
MEP Transaction			—				—				3
Net cash provided by (used in) investing activities			(1,766	)			—				3
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			2,108				92				1,858
Principal payments on debt			(162	)			(20	)			(1,632	)
Distributions to partners			(666	)			(526	)			(483	)
Debt issuance costs			(78	)			(24	)			(36	)
Net cash provided by (used in) financing activities			1,202				(478	)			(293	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(9	)			(9	)			27
CASH AND CASH EQUIVALENTS, beginning of period			18				27				—
CASH AND CASH EQUIVALENTS, end of period		$	9			$	18			$	27

 

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Prospectus

 

Energy Transfer Equity, L.P.

Debt Securities

 

 

We may offer and sell 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 debt 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 debt securities and the general manner in which we will offer the debt securities. The specific terms of any 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 debt securities. We will provide a supplement to accompany this prospectus each time we offer any debt securities. You should read this prospectus and the accompanying prospectus supplement carefully before you invest.

Investing in our debt securities involves risks. See “Risk Factors” beginning on page 5 of this prospectus.

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 November 14, 2013.

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ABOUT THIS PROSPECTUS			1
ENERGY TRANSFER EQUITY, L.P.			1
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS			3
RISK FACTORS			5
USE OF PROCEEDS			5
RATIO OF EARNINGS TO FIXED CHARGES			5
DESCRIPTION OF DEBT SECURITIES			6
PLAN OF DISTRIBUTION			9
LEGAL MATTERS			10
EXPERTS			10
WHERE YOU CAN FIND MORE INFORMATION			12
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE			12

In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus or the accompanying prospectus supplement. 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 or the accompanying prospectus supplement 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 (the “SEC”) using a “shelf” registration process. Under this shelf registration process, we may offer and sell the debt securities described in this prospectus in one or more offerings. This prospectus generally describes Energy Transfer Equity, L.P. and the debt 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” and any additional information you may need to make your investment decision. 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.

All references in this prospectus to “we,” “us,” “Energy Transfer Equity” and “our” refer to Energy Transfer Equity, L.P. and its subsidiaries. All references in this prospectus to “our general partner” refer to LE GP, LLC.

ENERGY TRANSFER EQUITY, L.P.

We are a publicly traded Delaware limited partnership (NYSE: ETE) that directly and indirectly owns equity interests in Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP”) and Regency Energy Partners LP (NYSE:RGP) (“Regency”), both of which are publicly traded master limited partnerships engaged in diversified energy-related services.

As of October 31, 2013, our equity interests in ETP and Regency consisted of:

 

		General Partner Interest (as a % of total partnership interest)				Incentive Distribution Rights				Common Units				Other
ETP			0.8	%			100	%			49,551,069	(1)			50,160,000 Class H Units	(3)
Regency			1.3	%			100	%			26,266,791	(2)			—

 

(1)	Represented an approximate 15.0% limited partner interest in ETP.

(2)	Represented an approximate 12.5% limited partner interest in Regency.

(3)

The Class H Units entitle us to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses and other items allocated to ETP by Sunoco Partners LLC (“SXL GP”), the general partner of Sunoco Logistics Partners L.P. (NYSE: SXL) (“SXL”), with respect to the incentive distribution rights and general partner interest in SXL held by SXL GP, (ii) distributions from ETP for each quarter equal to 50.05% of the cash distributed to ETP by SXL GP with respect to the incentive distribution rights and general partner interest in SXL held by SXL GP for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters, and (iii) incremental cash distributions in the aggregate amount of $329 million, subject to adjustment, to be payable by ETP to us over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017.

The following is a brief description of ETP’s and Regency’s operations:

 

•

ETP is a publicly-traded limited partnership owning and operating a diversified portfolio of energy assets in the United States. ETP owns and operates approximately 43,000 miles of natural gas, natural gas liquids (“NGLs”), refined products and crude oil pipelines. ETP owns 100% of ETP Holdco Corporation, which owns Southern Union Company and Sunoco, Inc., and a 70% interest in Lone Star NGL LLC, a joint venture that owns and operates NGL storage, fractionation and transportation assets.

 

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ETP also owns the general partner, 100% of the incentive distribution rights and approximately 33.5 million common units in SXL, which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets.

 

•

Regency is a growth-oriented, midstream energy partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of natural gas liquids. RGP also owns a 30% interest in Lone Star NGL LLC, a joint venture that owns and operates natural gas liquids 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 and the documents we incorporate by reference contain 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,” “estimate,” “intend,” “could,” “believe,” “may,” “will” 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:

 

•

the ability of our subsidiaries, ETP and Regency, to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

 

•

the actual amount of cash distributions by ETP and Regency to us;

 

•

the volumes transported on our subsidiaries’ pipelines and gathering systems;

 

•

the level of throughput in our subsidiaries’ processing and treating facilities;

 

•

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

 

•

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

 

•

energy prices generally;

 

•

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

 

•

the general level of petroleum product demand and the availability and price of NGL supplies;

 

•

the level of domestic oil, natural gas and NGL production;

 

•

the availability of imported oil, natural gas and NGLs;

 

•

actions taken by foreign oil and gas producing nations;

 

•

the political and economic stability of petroleum producing nations;

 

•

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

 

•

availability of local, intrastate and interstate transportation systems;

 

•

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

 

•

availability and marketing of competitive fuels;

 

•

the impact of energy conservation efforts;

 

•

energy efficiencies and technological trends;

 

•

governmental regulation and taxation;

 

•

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

 

•

hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

 

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competition from other midstream companies and interstate pipeline companies;

 

•

loss of key personnel;

 

•

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

 

•

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

 

•

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

 

•

the nonpayment or nonperformance by our subsidiaries’ customers;

 

•

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

 

•

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

 

•

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

 

•

a deterioration of the credit and capital markets;

 

•

risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interest, including risks related to management actions at such entities that our subsidiaries may not be able to control or influence;

 

•

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;

 

•

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

 

•

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. Any forward-looking statement made by us in this prospectus and the documents incorporated by reference into this prospectus is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

 

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RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. You should carefully consider the risk factors and all of the other information included in, or incorporated by reference into, this prospectus or any prospectus supplement, including those included in our most recent Annual Report on Form 10-K and, if applicable, in our Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, 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 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 those securities in the prospectus supplement.

USE OF PROCEEDS

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

RATIO OF EARNINGS TO FIXED CHARGES

The table below sets forth our ratio of earnings to fixed charges for the periods indicated on a consolidated historical basis. For purposes of determining the ratio of earnings to fixed charges, earnings are defined as pre-tax income from continuing operations before adjustment for income or loss from equity investees, plus fixed charges, amortization of capitalized interest, and distributed income from equity investees, minus capitalized interest. Fixed charges consist of net interest expense (inclusive of credit facility commitment fees) on all indebtedness, capitalized interest, the amortization of deferred financing costs, and interest associated with operating leases, if any.

 

		Years Ended December 31,																				Nine Months Ended September 30,
		2008				2009				2010				2011				2012				2013
Ratio of Earnings to Fixed Charges			2.73				2.37				1.50				1.70				2.18				2.12

 

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DESCRIPTION OF DEBT SECURITIES

Energy Transfer Equity, L.P. may issue senior debt securities under an indenture dated September 20, 2010 between Energy Transfer Equity, L.P., as issuer, and U.S. Bank National Association, as trustee. We refer to this 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.

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 Debt Securities” to “we,” “us” and “our” mean Energy Transfer Equity, L.P., and not any of our subsidiaries.

Provisions Applicable to the Indenture

Except as may be provided in a prospectus supplement relating to an issuance of debt securities, the indenture does not limit the amount of debt securities that may be issued under any 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.

Except as may be provided in a prospectus supplement relating to an issuance of debt securities, 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. Except as may be provided in a prospectus supplement relating to an issuance of debt securities, 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, 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 that 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;

 

•

whether debt securities are entitled to the benefits of any guarantee of any subsidiary guarantor;

 

•

whether debt securities are secured by any of our or any guarantor’s, if any, assets;

 

•

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

 

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any provisions for optional redemption or early repayment;

 

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

 

•

the denominations in which the debt securities will be issued;

 

•

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. We will describe in the prospectus supplement the terms of events of default with respect to a series of debt securities and all provisions relating thereto.

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. We will describe in the prospectus supplement the terms that may not be modified without the consent of the holder of each debt security affected with respect to a series of debt securities.

Defeasance. When we use the term defeasance, we mean discharge from some or all of our obligations under the indenture. We will describe in the prospectus supplement the provisions applicable to defeasance with respect to a series of debt securities.

Governing Law. New York law governs 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.

 

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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 applicable 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.

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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PLAN OF DISTRIBUTION

Under this prospectus, we intend to offer our debt securities to the public through underwriters or directly to investors.

We will fix a price or prices of our debt securities at negotiated prices.

We may change the price of the debt securities offered from time to time.

To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in prospectus supplements. In that event, the discounts and commissions we will allow or pay to the underwriters, if any, and the discounts and commissions the underwriters may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplements. Any underwriters, brokers, dealers and agents who participate in any sale of the debt securities may also engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses. We may indemnify underwriters, brokers, dealers and agents against specific liabilities, including liabilities under the Securities Act of 1933, as amended (the “Securities Act”).

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution.

 

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LEGAL MATTERS

Latham & Watkins LLP, Houston, Texas, will pass upon the validity of the debt securities offered in this registration statement. If certain legal matters in connection with an offering of the debt securities made by this prospectus and a related prospectus supplement are passed upon 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 of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Energy Transfer Partners, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Energy Transfer Partners GP, L.P. and subsidiaries as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, included in this prospectus have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Regency Energy Partners LP and subsidiaries as of December 31, 2012 and 2011 and for the years then ended, and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2012, incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of RIGS Haynesville Partnership Co. and subsidiaries as of December 31, 2012 and 2011 and for the years then ended incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Lone Star NGL LLC and subsidiaries as of December 31, 2012 and 2011 and for the year ended December 31, 2012 and for the period from inception (March 21, 2011) to December 31, 2011 incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Southern Union Gathering Company, LLC and subsidiaries as of December 31, 2012 and for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012 incorporated by reference in this prospectus have been so incorporated by reference in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

 

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The consolidated financial statements of Regency Energy Partners LP for the period from May 26, 2010 to December 31, 2010 and the period from January 1, 2010 to May 25, 2010 have been incorporated by reference herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, included herein, and upon the authority of said firm as experts in accounting and auditing.

The financial statements of RIGS Haynesville Partnership Co. as of and for the year ended December 31, 2010 included in Exhibit 99.3 of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of KPMG LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Midcontinent Express Pipeline LLC as of and for the years ended December 31, 2012 and 2011 and as of December 31, 2011 and 2010 and for the year ended December 31, 2011 and for the seven-month period ended December 31, 2010, included in Exhibits 99.4 and 99.5, respectively, of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of LDH Energy Asset Holdings LLC as of December 31, 2010 and 2009 and for the three year period ended December 31, 2010 included in Exhibit 99.7 of Regency Energy Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2012 have been so incorporated in this prospectus in reliance on the report of Ernst & Young LLP, independent auditors, given on the authority of said firm as experts in auditing and accounting.

 

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WHERE YOU CAN FIND MORE INFORMATION

This prospectus, including any documents incorporated herein by reference, constitutes a part of a registration statement on Form S-3 that we filed with the SEC under the Securities Act. This prospectus does not contain all the information set forth in the registration statement. You should refer to the registration statement and its related exhibits and schedules, and the documents incorporated herein by reference, for further information about ETE and the debt securities offered in this prospectus. Statements contained in this prospectus concerning the provisions of any document are not necessarily complete and, in each instance, reference is made to the copy of that document filed as an exhibit to the registration statement or otherwise filed with the SEC, and each such statement is qualified by this reference. The registration statement and its exhibits and schedules, and the documents incorporated herein by reference, are on file at the offices of the SEC and may be inspected without charge.

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

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

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

We are incorporating by reference in this prospectus information we file with the SEC, which means that we are disclosing important information to you by referring you to those documents. The information we incorporate by reference is an important part of this prospectus, and later information that we file with the SEC automatically will update and supersede this information and will be considered a part of this prospectus from the date those documents are filed. We incorporate by reference the documents listed below and any future filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, excluding any information in those documents that is deemed by the rules of the SEC to be furnished and not filed, after the date of this prospectus and prior to the termination of an offering:

 

•

our Annual Report on Form 10-K for the year ended December 31, 2012;

 

•

our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013 and September 30, 2013;

 

•

our Current Reports on Form 8-K filed February 14, 2013, February 28, 2013, March 26, 2013, April 2, 2013, April 4, 2013, May 1, 2013 (which was amended by Form 8-K/A on May 6, 2013), June 24, 2013, August 8, 2013, October 25, 2013, November 1, 2013 and November 14, 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);

 

•

audited financial statements of ETP for the year ended December 31, 2012 included in ETP’s Annual Report on Form 10-K filed March 1, 2013;

 

•

unaudited financial statements of ETP for the nine months ended September 30, 2013 included in ETP’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013;

 

•

audited financial statements of Regency for the year ended December 31, 2012 included in Regency’s Current Report on Form 8-K filed August 9, 2013;

 

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unaudited financial statements of Regency for the nine months ended September 30, 2013 included in Regency’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013;

 

•

audited financial statements of Midcontinent Express Pipeline LLC for the years ended December 31, 2012 and 2011 and for the seven month period ended December 31, 2010 included in Regency’s Annual Report on Form 10-K for the year ended December 31, 2012 (the “Regency 2012 10-K”);

 

•

audited financial statements of RIGS Haynesville Partnership Co. as of and for the years ended December 31, 2012 and 2011 and as of and for the year ended December 31, 2010 included in the Regency 2012 10-K;

 

•

audited financial statements of Lone Star NGL LLC as of and for the year ended December 31, 2012 and for the period from March 21, 2011 to December 31, 2011, included in the Regency 2012 10-K;

 

•

audited financial statements of LDH Energy Asset Holdings LLC as of December 31, 2010 and 2009 and for the three year period ended December 31, 2010 included in the Regency 2012 10-K; and

 

•

audited financial statements of Southern Union Gathering Company as of December 31, 2012 and for the period from March 26, 2012 to December 31, 2012 and for the period from January 1, 2012 to March 25, 2012 included in Exhibit 99.2 of Regency Energy Partners LP’s Current Report on Form 8-K filed on April 12, 2013.

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s web site 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 web site at the address provided above or by writing or calling us at the address set forth below.

Energy Transfer Equity, L.P.

3738 Oak Lawn Avenue

Dallas, Texas 75219

Attention: Sonia Aubé

Telephone: (214) 981-0700

 

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