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ETE 09-30-2013 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)



Delaware		30-0108820
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	ý	Accelerated filer	¨

Non-accelerated filer	£ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

At November 1, 2013, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 280,711,650 Common Units

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FORM 10-Q

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets – September 30, 2013 and December 31, 2012	1

Consolidated Statements of Operations – Three and Nine Months Ended September 30, 2013 and 2012	3

Consolidated Statements of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2013 and 2012	4

Consolidated Statement of Equity – Nine Months Ended September 30, 2013	5

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2013 and 2012	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57

ITEM 4. CONTROLS AND PROCEDURES	60

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	61

ITEM 1A. RISK FACTORS	61

ITEM 6. EXHIBITS	62

SIGNATURE	63

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections 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, the Partnership’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission on March 1, 2013.

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

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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

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.

iii

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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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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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.


•	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.

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▪	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, 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.

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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 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.

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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.


•	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.

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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.


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

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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		$	—
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	)

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	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		$	—
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	)

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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
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	)

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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.

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.

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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.

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

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.

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.

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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 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.

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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.

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.

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•	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

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	)

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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.

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 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.

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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 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.

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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 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.

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.

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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 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.

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•	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.


•	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.

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

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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 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.

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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.

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

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⁽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 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

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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

ETP

July 2018

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

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

Southern Union

November 2021

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

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.

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

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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	)

In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

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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



	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

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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
		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

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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 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.

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	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



	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

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	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

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

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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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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

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 included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 1, 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 “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended 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 and Regency. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At October 31, 2013, our interests in ETP and Regency consisted of:



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

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 distributions to its partners, 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.

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 Holdco.

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RECENT DEVELOPMENTS

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. 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.

Sale of AmeriGas Common Units

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.

Class H Units

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.

LNG Export License

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.

Sale of Distribution Operations

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Regency’s Acquisition of PVR Partners, L.P.

Retail Acquisition

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.

ETE Refinancing Activities

On October 30, 2013, ETE commenced a tender offer to purchase for cash up to an aggregate of $400 million principal amount of its outstanding 7.50% Senior Notes due 2020 (the “ETE Notes”), which maximum tender offer amount may be increased at ETE’s election, subject to applicable law. In conjunction with the tender offer, ETE intends to launch a comprehensive refinancing of its existing debt. To that end, ETE intends to refinance its current $900 million senior secured term loan due March 2017 and is also working with a number of selected banks in finalizing a new five-year revolving credit facility for up to $600 million. Proceeds from a possible new issuance of senior secured notes and/or a new term loan will be used to satisfy any proceeds required for a successful tender of the ETE Notes. There can be no assurance that ETE will successfully refinance its existing term loan or raise adequate funds for the tender from any intended new issuance of senior secured notes or any term loan financing.

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 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 adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation.

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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 consolidated financial statements.

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

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•	additional depreciation and amortization related to assets placed in service.

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 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 to AmeriGas in January 2012.

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 senior notes in June 2013 and $8 million in connection with its repurchase of senior notes in May 2012.

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 PES.

Adjusted EBITDA Related to Discontinued Operations. Amounts reflect the operations of 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.

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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 that each 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.

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.


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

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(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 Corp. 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 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

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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 Canyon, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

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

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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 attributable 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.

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 respective business activities and the amount of available cash, as discussed below. 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.

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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 ETP’s midstream operations 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 its 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 included these factors in its anticipated growth capital expenditures for each year.

ETP generally funds its capital requirements with cash flows from operating activities, borrowings under the ETP Credit Facility, the issuance of long-term debt or ETP Common Units or a combination thereof. Based on ETP’s current estimates, it expects to utilize capacity under the ETP 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 the Regency 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 operations; and $220 million is expected to be invested in growth capital expenditures in its contract services operations. 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.

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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 compared to nine months ended September 30, 2012. Cash provided by operating activities during 2013 was $1.85 billion as compared to $897 million for 2012. Net income was $1.02 billion and $1.00 billion for 2013 and 2012, respectively. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $944 million and $138 million and changes in operating assets and liabilities of $382 million and $120 million for 2013 and 2012, respectively.

The non-cash activity in 2013 consisted primarily of depreciation and amortization of $962 million compared to $571 million in 2012. The non-cash activity in 2012 consisted primarily of the gain on deconsolidation of Propane Business of $1.06 billion, the loss on extinguishment of debt of $123 million, and bridge loan related fees of $62 million which were not reflected in 2013.

Cash paid for interest, net of interest capitalized, was $944 million and $696 million for the nine months ended September 30, 2013 and 2012, respectively.

Capitalized interest for the nine months ended September 30, 2013 was $32 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 compared to nine months ended September 30, 2012. Cash used in investing activities during 2013 was $833 million as compared to $3.61 billion for 2012. In 2013, we received $973 million and $346 million in cash from the sale of the MGE assets and the sale of AmeriGas common units, respectively. In 2012, we paid cash for acquisitions of $2.98 billion, which primarily consisted of our acquisition of Southern Union for $2.97 billion. 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. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2012 of $2.24 billion, including changes in accruals of $231 million. In 2012, ETP also received cash proceeds from its contribution and sale of propane operations of $1.44 billion.

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 compared to nine months ended September 30, 2012. Cash used in financing activities during 2013 was $209 million as compared to cash provided by financing activities of $2.76 billion for 2012. In 2013, ETP received $1.30 billion in net proceeds from offerings of ETP Common Units as compared to $772 million in 2012. In 2013,

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Regency received $149 million in net proceeds from offerings of Regency Common Units as compared to $312 million in 2012. During 2013, we had a consolidated net increase in our debt level of $329 million as compared to a net increase of $2.94 billion for 2012. We paid distributions of $544 million and $491 million to our partners in 2013 and in 2012, respectively. Our subsidiaries paid distributions to noncontrolling interest of $1.05 billion and $688 million in 2013 and 2012, respectively. In 2013, we also paid $340 million to redeem our Preferred Units.

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 and in Note 8 to our consolidated financial statements.

Parent Company 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 on 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 Senior Note Offerings

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 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 the ETP Credit Facility and for general partnership purposes.

In September 2013, Regency issued $400 million aggregate principal amount of 5.75% senior notes due September 2020. Regency used the net proceeds of approximately $394 million to repay borrowings outstanding under the Regency 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 Credit Facility is secured by all of the Parent Company’s 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

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 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, there was a balance outstanding under the Regency Credit Facility 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 Southern Union Credit Facility and the facility was terminated.

Sunoco Logistics Credit Facilities

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.

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, 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 the General Partner that is necessary or appropriate to provide for future cash requirements.

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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

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,
	2013		2012
Limited Partners	$	554	$	525
General Partner interest	1		1
Total Parent Company distributions	$	555	$	526

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. 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 IDRs (shown in the period to which they relate) for the periods ended as noted below is as follows:



	Nine Months Ended September 30,
	2013			2012
Distributions from ETP:
Limited Partners ⁽¹⁾	$	223		$	135
Class H Units held by ETE Holdings	16			—
General Partner interest	15			15
IDRs	528			381
IDR relinquishments related to previous transactions ⁽²⁾	(107		)	(59		)
Total distributions from ETP ⁽³⁾	675			472
Distributions from Regency:
Limited Partners	36			36
General Partner interest	3			4
IDRs	8			6
IDR relinquishment related to previous transaction ⁽⁴⁾	(2		)	—
Total distributions from Regency	45			46
Total distributions received from subsidiaries	$	720		$	518


⁽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⁾	Following are 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.

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•	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 in Note 10 to our consolidated financial statements, 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.



	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 G Units, which are held by subsidiaries of 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, 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

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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,
	2013			2012
Limited Partners	$	979		$	694
General Partner interest	15			15
IDRs	528			381
IDR relinquishments related to previous transactions	(107		)	(59		)
Total ETP distributions	$	1,415		$	1,031

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 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

The total amounts of Regency distributions declared and/or paid during the nine months ended September 30, 2013 and 2012 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,
	2013			2012
Limited Partners	$	289		$	235
General Partner interest	3			4
IDRs	8			6
IDR relinquishment related to previous transaction	(2		)	—
Total Regency distributions	$	298		$	245

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
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

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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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2012, in addition to the interim unaudited consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2012.

Commodity Price Risk

The tables below summarize by operating entity commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of September 30, 2013 and December 31, 2012.

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Our consolidated balance sheets also reflect assets and liabilities related to commodity derivatives that have previously been de-designated as cash flow hedges or for which offsetting positions have been entered. Those amounts are not subject to change based on changes in prices.

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ETP

Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power, gallons for propane and barrels for NGLs, refined products and crude. Dollar amounts are presented in millions.



	September 30, 2013								December 31, 2012
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change			Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives			(in millions)								(in millions)
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	6,560,000		$	(2	)	$	3		—		$	—		$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	(27,402,500	)	(4		)	1			(30,980,000	)	(6		)	—
Swings Swaps IFERC	1,690,000		—			1			—		—			—
Power (Megawatt):
Forwards	562,250		1			2			19,650		—			1
Futures	97,212		—			1			(1,509,300	)	(1		)	1
Options — Calls	(1,700	)	(2		)	—			1,656,400		2			1
Crude (Bbls) — Futures	80,000		—			(1		)	—		—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(5,300,000	)	(1		)	—			150,000		(1		)	—
Swing Swaps IFERC	6,965,000		(1		)	2			(83,292,500	)	1			1
Fixed Swaps/Futures	(14,072,500	)	13			5			27,077,500		(7		)	9
Forward Physical Contracts	(11,663,485	)	1			—			11,689,855		—			2
Natural Gas Liquid (Bbls):
Forwards/Swaps	(1,182,000	)	1			6			(30,000	)	—			—
Refined Products (Bbls) — Futures	(93,327	)	8			—			(666,000	)	(3		)	14
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(6,577,500	)	—			—			(18,655,000	)	(1		)	—
Fixed Swaps/Futures	(47,215,000	)	16			18			(44,272,500	)	4			15
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,150,000	)	—			—			—		—			—
Fixed Swaps/Futures	(5,720,000	)	—			2			(8,212,500	)	(3		)	3
Natural Gas Liquid (Bbls):
Forwards/Swaps	(720,000	)	1			4			(930,000	)	(2		)	7
Refined Products (Bbls) — Futures	—		—			—			(98,000	)	—			1
Crude (Bbls) — Futures	(120,000	)	(2		)	1			—		—			—

⁽¹⁾ Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

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Regency

Notional volumes are presented in MMBtu for natural gas, gallons for propane and barrels for NGLs and WTI crude oil. Dollar amounts are presented in millions.



	September 30, 2013						December 31, 2012
	Notional Volume	Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas:
Fixed Swaps/Futures	15,176,000	$	5		$	6	8,395,000	$	1	$	3
Propane:
Forwards/Swaps	33,642,000	(2		)	3		3,318,000	1		1
NGLs:
Forwards/Swaps	144,000	1			1		243,000	—		2
WTI Crude Oil:
Forwards/Swaps	829,000	(2		)	7		356,000	2		3

Interest Rate Risk

As of September 30, 2013, we and our subsidiaries had $1.72 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $17 million annually. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements. To the extent that we have debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates.

The following interest rate swaps were outstanding as of September 30, 2013 and December 31, 2012 (dollars in millions), none of which are 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

ETP

July 2018

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

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

Southern Union

November 2021

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

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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A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in losses on interest rate derivatives) of $1 million as of September 30, 2013 and $118 million as of December 31, 2012. For the $1.2 billion of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $12 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled. For Southern Union’s interest rate swaps, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $5 million.

Credit Risk

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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2013 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2012 and Note 14 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Partners, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2013.

In September 2013, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation and proposed penalties in excess of $0.1 million based on alleged violations of various safety regulations relating to the November 2008 products release by Sunoco Pipeline, L.P., a subsidiary of Sunoco Logistics, in Murrysville, Pennsylvania. Sunoco Logistics is currently in discussions with the PADEP. The timing or outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for our previous fiscal year ended December 31, 2012.

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ITEM 6. EXHIBITS

The exhibits listed below are filed as part of this report:



	Exhibit Number	Description
(*)	10.1	Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC dated August 7, 2013.
	31.1	Certification of President pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(**)	32.1	Certification of President pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(**)	32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.INS	XBRL Instance Document
	101.SCH	XBRL Taxonomy Extension Schema Document
	101.CAL	XBRL Taxonomy Calculation Linkbase Document
	101.DEF	XBRL Taxonomy Extension Definitions Document
	101.LAB	XBRL Taxonomy Label Linkbase Document
	101.PRE	XBRL Taxonomy Presentation Linkbase Document



*	Indicates exhibit incorporated by reference to Energy Transfer Equity, L.P. Current Report on Form 8-K filed on August 8, 2013.
**	Furnished herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		ENERGY TRANSFER EQUITY, L.P.

		By:	LE GP, L.L.C., its General Partner

Date:	November 7, 2013	By:	/s/ Jamie Welch
			Jamie Welch
			Chief Financial Officer (duly authorized to sign on behalf of the registrant)

ETE-9.30.2013 Ex. 31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Energy Transfer Equity, L.P.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 7, 2013

/s/ John W. McReynolds

John W. McReynolds

President

ETE-9.30.2013 Ex. 31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jamie Welch, certify that:


1.	I have reviewed this quarterly report on Form 10-Q of Energy Transfer Equity, L.P.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 7, 2013

/s/ Jamie Welch

Jamie Welch

Chief Financial Officer

ETE-9.30.2013 Ex. 32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 7, 2013

/s/ John W. McReynolds

John W. McReynolds

President

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer Equity, L.P. and furnished to the Securities and Exchange Commission upon request.

ETE-9.30.2013 Ex. 32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jamie Welch, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: November 7, 2013

/s/ Jamie Welch

Jamie Welch

Chief Financial Officer