ET 10-Q Quarterly Report Sept. 30, 2012

ENERGY TRANSFER LP

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10-Q 1 ete-9302012xq3.htm 10-Q ETE-9.30.2012-Q3

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2012



¨	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, 2012 , the registrant had units outstanding as follows:

Energy Transfer Equity, L. P. 279,955,608 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, 2012 and December 31, 2011	1

Consolidated Statements of Operations – Three and Nine Months Ended September 30, 2012 and 2011	3

Consolidated Statements of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2012 and 2011	4

Consolidated Statement of Equity – Nine Months Ended September 30, 2012	5

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	48

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	67

ITEM 4. CONTROLS AND PROCEDURES	71

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	71

ITEM 1A. RISK FACTORS	71

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	80

ITEM 3. DEFAULTS UPON SENIOR SECURITIES	80

ITEM 4. MINE SAFETY DISCLOSURES	80

ITEM 5. OTHER INFORMATION	80

ITEM 6. EXHIBITS	80

SIGNATURE	81

Table of Contents

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 II — Other Information – Item 1A. Risk Factors” for the quarters ended March 31, 2012 and June 30, 2012 and included in this Quarterly Report on Form 10-Q, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 22, 2012 .

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

AROs		asset retirement obligations

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

CAA		Federal Clean Air Act

Canyon		ETC Canyon Pipeline, LLC

Capacity		capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

Citi		Citigroup Global Markets Inc.

Citrus		Citrus Corp., which owns 100% of FGT

Citrus Merger		ETP's acquisition of Citrus Corp. on March 26, 2012

CrossCountry		CrossCountry Energy LLC

CFTC		Commodities Futures Trading Commission

CRSA		Contingent Residual Support Agreement

DER		Distribution equivalent rights

DRIP		Distribution Reinvestment Plan

DOT		U.S. Department of Transportation

Enterprise		Enterprise Products Partners L.P., together with its subsidiaries

ETP		Energy Transfer Partners, L.P.

ETP Class F Units		Class F Units issued by ETP in Holdco Transaction

ETP Credit Facility		ETP's revolving credit facility

Table of Contents



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

FDOT/FTE		Florida Department of Transportation, Florida's Turnpike Enterprise

FEP		Fayetteville Express Pipeline LLC

FERC		Federal Energy Regulatory Commission

FGT		Florida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula

Finance Company		AmeriGas Finance LLC

GAAP		accounting principles generally accepted in the United States of America

HPC		RIGS Haynesville Partnership Co.

Holdco		ETP Holdco Corporation

Holdco Transaction		October 5, 2012 transaction including contributions from ETP and ETE to Holdco

HOLP		Heritage Operating, L.P.

IDRs		incentive distribution rights

LDH		LDH Energy Asset Holdings LLC

LIBOR		London Interbank Offered Rate

LNG		Liquefied natural gas

LNG Holdings		Trunkline LNG Holdings, LLC

Lone Star		Lone Star NGL LLC

MDPU		Massachusetts Department of Public Utilities

MEP		Midcontinent Express Pipeline LLC

MGP		manufactured gas plant

MMBtu		million British thermal units

NGL		natural gas liquid, such as propane, butane and natural gasoline

NMED		New Mexico Environmental Department

NYMEX		New York Mercantile Exchange

OTC		over-the-counter

Other Post-retirement Plans		postretirement health care and life insurance plans

Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCB		polychlorinated biphenyl

Pension Plans		funded non-contributory defined benefit pension plans

PEPL		Panhandle Eastern Pipe Line Company, LP

PHMSA		Pipeline Hazardous Materials Safety Administration

RIGS		Regency Intrastate Gas System

Preferred Units		ETE's Series A Convertible Preferred Units

iii

Table of Contents




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 GP		Regency Energy Partners GP LP, the general partner of Regency

Regency LLC		Regency Energy Partners GP LLC, the general partner of Regency GP

Regency Preferred Units		Regency's Series A Convertible Preferred Units, the Preferred Units of a Subsidiary

Sea Robin Pipeline		Sea Robin Pipeline Company LLC

SEC		Securities and Exchange Commission

Southern Union		Southern Union Company, a subsidiary of ETE

Southern Union Credit Facility		Southern Union's revolving credit facility

Southern Union Merger		ETE's acquisition of Southern Union on March 26, 2012

SUGS		Southern Union Gas Services

Sunoco		Sunoco, Inc.

Sunoco Logistics		Sunoco Logistics Partners L.P.

Sunoco Merger		ETP's acquisition of Sunoco on October 5, 2012

TCEQ		Texas Commission on Environmental Quality

Transwestern		Transwestern Pipeline Company, LLC

Trunkline LNG		Trunkline LNG 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 and unconsolidated affiliates based on proportionate ownership.

Table of Contents

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)



	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	172,076		$	126,342
Accounts receivable, net of allowance for doubtful accounts of $2,844 and $8,841 as of September 30, 2012 and December 31, 2011, respectively	822,109			680,491
Accounts receivable from related companies	38,956			100,406
Inventories	450,212			327,963
Exchanges receivable	44,030			21,307
Price risk management assets	31,615			15,802
Current assets held for sale	7,482			—
Other current assets	170,942			183,133
Total current assets	1,737,422			1,455,444

PROPERTY, PLANT AND EQUIPMENT	24,157,556			16,529,339
ACCUMULATED DEPRECIATION	(1,920,506		)	(1,970,777		)
	22,237,050			14,558,562

NON-CURRENT ASSETS HELD FOR SALE	190,996			—
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,500,273			1,496,600
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	43,566			26,011
GOODWILL	3,458,807			2,038,975
INTANGIBLE ASSETS, net	953,924			1,072,291
OTHER NON-CURRENT ASSETS, net	475,561			248,910
Total assets	$	33,597,599		$	20,896,793

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 thousands)

(unaudited)



	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	554,022		$	512,023
Accounts payable to related companies	3,740			33,208
Exchanges payable	112,645			17,957
Price risk management liabilities	119,481			90,053
Accrued and other current liabilities	1,130,528			763,912
Current maturities of long-term debt	614,418			424,160
Current liabilities held for sale	5,439			—
Total current liabilities	2,540,273			1,841,313

LONG-TERM DEBT, less current maturities	17,525,668			10,946,864
PREFERRED UNITS	327,960			322,910
DEFERRED INCOME TAXES	1,954,144			217,244
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	173,838			81,415
OTHER NON-CURRENT LIABILITIES	311,713			26,958

COMMITMENTS AND CONTINGENCIES (Note 16)

PREFERRED UNITS OF SUBSIDIARY	72,549			71,144

EQUITY:
General Partner	(161		)	321
Limited Partners:
Common Unitholders	2,203,817			52,485
Accumulated other comprehensive income (loss)	(5,747		)	678
Total partners’ capital	2,197,909			53,484
Noncontrolling interest	8,493,545			7,335,461
Total equity	10,691,454			7,388,945
Total liabilities and equity	$	33,597,599		$	20,896,793

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 thousands, except per unit data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES:
Natural gas sales	$	789,634		$	796,323		$	1,928,913		$	2,320,208
NGL sales	584,475			507,616			1,704,860			1,187,616
Gathering, transportation and other fees	635,340			479,279			1,724,756			1,335,201
Retail propane sales	—			213,496			87,082			962,258
Other	161,513			87,300			364,910			219,600
Total revenues	2,170,962			2,084,014			5,810,521			6,024,883
COSTS AND EXPENSES:
Cost of products sold	1,244,418			1,347,587			3,250,485			3,807,320
Operating expenses	216,673			230,909			645,129			667,084
Depreciation and amortization	219,458			151,429			589,080			426,216
Selling, general and administrative	124,380			82,564			395,584			224,957
Total costs and expenses	1,804,929			1,812,489			4,880,278			5,125,577
OPERATING INCOME	366,033			271,525			930,243			899,306
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(237,802		)	(193,772		)	(732,387		)	(543,218		)
Bridge loan related fees	—			—			(62,241		)	—
Equity in earnings of unconsolidated affiliates	19,924			28,374			117,619			82,634
Gain on deconsolidation of Propane Business	—			—			1,056,709			—
Losses on extinguishments of debt	—			—			(122,844		)	—
Losses on non-hedged interest rate derivatives	(6,118		)	(68,497		)	(23,296		)	(65,094		)
Other, net	(84		)	27,902			28,628			15,752
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	141,953			65,532			1,192,431			389,380
Income tax expense	28,625			3,290			40,379			18,415
INCOME FROM CONTINUING OPERATIONS	113,328			62,242			1,152,052			370,965
Loss from discontinued operations	(147,162		)	(1,543		)	(150,062		)	(4,522		)
NET INCOME (LOSS)	(33,834		)	60,699			1,001,990			366,443
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST	(69,004		)	(8,384		)	746,900			142,435
NET INCOME ATTRIBUTABLE TO PARTNERS	35,170			69,083			255,090			224,008
GENERAL PARTNER’S INTEREST IN NET INCOME	87			214			725			693
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	35,083		$	68,869		$	254,365		$	223,315
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.65		$	0.32		$	1.54		$	1.02
Diluted	$	0.65		$	0.32		$	1.54		$	1.02
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.13		$	0.31		$	0.97		$	1.00
Diluted	$	0.13		$	0.31		$	0.97		$	1.00

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 thousands)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income (loss)	$	(33,834	)	$	60,699		$	1,001,990		$	366,443
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(7,119		)	288			(14,933		)	(13,129		)
Change in value of derivative instruments accounted for as cash flow hedges	(6,897		)	16,412			14,251			9,403
Change in value of available-for-sale securities	—			(900		)	(114		)	(935		)
Change in other comprehensive income from equity investments	8,437			—			(13,771		)	—
	(5,579		)	15,800			(14,567		)	(4,661		)
Comprehensive income (loss)	(39,413		)	76,499			987,423			361,782
Less: Comprehensive income (loss) attributable to noncontrolling interest	(67,527		)	4,323			738,758			139,836
Comprehensive income attributable to partners	$	28,114		$	72,176		$	248,665		$	221,946

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, 2012

(Dollars in thousands)

(unaudited)



	General Partner			Common Unitholders			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2011	$	321		$	52,485		$	678		$	7,335,461		$	7,388,945
Distributions to partners	(1,298		)	(489,303		)	—			—			(490,601		)
Distributions to noncontrolling interest	—			—			—			(687,917		)	(687,917		)
Units issued in Southern Union Merger (See Note 3)	—			2,354,490			—			—			2,354,490
Subsidiary units issued for cash	94			32,498			—			1,051,390			1,083,982
Subsidiary units issued in certain acquisitions	—			—			—			7,000			7,000
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			492			—			33,233			33,725
Capital contributions from noncontrolling interest	—			—			—			23,836			23,836
Other, net	(3		)	(1,210		)	—			(8,216		)	(9,429		)
Other comprehensive loss, net of tax	—			—			(6,425		)	(8,142		)	(14,567		)
Net income	725			254,365			—			746,900			1,001,990
Balance, September 30, 2012	$	(161	)	$	2,203,817		$	(5,747	)	$	8,493,545		$	10,691,454

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 thousands)

(unaudited)



	Nine Months Ended September 30,
	2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,001,990			$	366,443
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	589,080				426,216
Deferred income taxes	37,315				(479		)
Gain on curtailment of other postretirement benefit plans	(15,332		)		—
Amortization of finance costs charged to interest	6,248				14,581
Bridge loan related fees	62,241				—
Non-cash compensation expense	34,411				34,429
Gain on deconsolidation of Propane Business	(1,056,709		)		—
Losses on extinguishments of debt	122,844				—
Write-down of assets included in loss from discontinued operations (Note 3)	145,214				—
Equity in earnings of unconsolidated affiliates	(117,619		)		(82,634		)
Distributions from unconsolidated affiliates	153,119				89,196
Other non-cash	54,187				21,032
Changes in operating assets and liabilities, net of effects of acquisitions and deconsolidation	(119,773		)		234,176
Net cash provided by operating activities	897,216				1,102,960
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received (Note 3)	(2,971,588		)		—
Cash paid for acquisitions, net of cash received	(10,317		)		(1,971,438		)
Capital expenditures (excluding allowance for equity funds used during construction)	(2,238,730		)		(1,232,059		)
Contributions in aid of construction costs	28,022				18,435
Contributions to unconsolidated affiliates	(34,693		)		(221,365		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	139,118				54,859
Proceeds from the sale of assets	35,475				15,570
Cash proceeds from contribution of propane operations	1,442,536				—
Other	(2,872		)	—	—
Net cash used in investing activities	(3,613,049		)		(3,335,998		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	9,081,100				6,429,107
Repayments of long-term debt	(6,144,208		)		(4,130,493		)
Subsidiary equity offering, net of issue costs	1,083,982				1,003,209
Distributions to partners	(490,601		)		(385,806		)
Debt issuance costs	(98,789		)		(22,217		)
Distributions to noncontrolling interest	(687,917		)		(574,285		)
Capital contributions received from noncontrolling interest	23,836				—
Other, net	(5,836		)		(5,026		)
Net cash provided by financing activities	2,761,567				2,314,489
INCREASE IN CASH AND CASH EQUIVALENTS	45,734				81,451
CASH AND CASH EQUIVALENTS, beginning of period	126,342				86,264
CASH AND CASH EQUIVALENTS, end of period	$	172,076			$	167,715

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)


1.	OPERATIONS AND ORGANIZATION:

Business Operations

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, and Southern Union. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

At September 30, 2012 , our equity interests in ETP and Regency consisted of:



	General Partner Interest (as a % of total partnership interest)		IDRs		Common Units	Limited Partner Ownership (as a % and net of any treasury units)
ETP	1.4	%	100	%	52,476,059	21	%
Regency	1.6	%	100	%	26,266,791	15	%

On March 26, 2012 , we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57.0 million ETE Common Units. On October 5, 2012, ETP completed the Sunoco Merger and Holdco Transaction. See Note 3 for more information regarding the Southern Union Merger, Sunoco Merger and Holdco Transaction.

The unaudited consolidated financial statements of ETE presented herein for the three and nine month periods ended September 30, 2012 and 2011 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”);


•	our wholly-owned subsidiary, Southern Union (see description of its operations below under “Business Operations”); and


•	ETP’s, Regency’s and Southern Union’s wholly-owned subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

Our unaudited consolidated financial statements include the results of operations of Southern Union from March 26, 2012 , the date we acquired Southern Union, through September 30, 2012 .

Business Operations

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union, the Parent Company also generated cash flows through its wholly-owned subsidiary, Southern Union. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 21 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of our operating entities prior to the completion of the Sunoco Merger and Holdco Transaction on October 5, 2012:

•

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Alabama, Arizona, Arkansas, Colorado, Louisiana, Mississippi, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star, a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas,

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Louisiana and Mississippi. Concurrent with the Parent Company's acquisition of Southern Union, ETP acquired a 50% interest in Citrus, which owns FGT (see Note 3).

•

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•

Southern Union is engaged primarily in the transportation, storage, gathering, processing and distribution of natural gas. Southern Union owns and operates interstate pipeline that transports natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions. It owns and operates a LNG import terminal located on Louisiana's Gulf Coast. Through SUGS, it owns natural gas and NGL pipelines, cryogenic plants, treating plants and is engaged in connecting producing wells of exploration and production companies to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs and redelivering natural gas and NGLs to a variety of markets in West Texas and New Mexico. Southern Union also has regulated utility operations in Missouri and Massachusetts.

See Note 20 for discussion regarding our reportable segments.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2011 , 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, 2012 and for the three and nine months ended September 30, 2012 and 2011 , 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. Management has evaluated subsequent events through the date the financial statements were issued.

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, 2012 , and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2012 and 2011 . 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, 2011 , as filed with the SEC on February 22, 2012 .

Certain prior period amounts have been reclassified to conform to the 2012 presentation. These reclassifications had no impact on net income or total equity.


2.	ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill

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impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.

Significant Accounting Policies

As a result of the Southern Union Merger on March 26, 2012 , the following significant accounting policies have been added to our significant accounting policies described in our Form 10-K for the year ended December 31, 2011.

Pensions and Other Postretirement Benefit Plans

Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive income in equity. See Note 14 for further information regarding pensions and other postretirement benefit plans.

Revenue Recognition for Southern Union's Natural Gas Distribution Operations

In Southern Union's natural gas distribution operations, natural gas utility customers are billed on a monthly-cycle basis. The related cost of natural gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased natural gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction. Revenues from natural gas delivered but not yet billed are accrued, along with the related natural gas purchase costs and revenue-related taxes.


3.	ACQUISITIONS AND DIVESTITURES:

Southern Union Merger

On March 26, 2012 , Sigma Acquisition Corporation, a Delaware corporation and a wholly-owned subsidiary of ETE, completed its acquisition of Southern Union. Southern Union is the surviving entity in the merger and operates as a wholly-owned subsidiary of ETE. The assets acquired as a result of this merger significantly expand our existing geographic footprint of natural gas pipeline and natural gas transportation capacity and into natural gas utilities distribution, and are complementary to the assets owned and operated by our other entities.

Under the terms of the merger agreement, Southern Union stockholders received a total of 56,982,160 ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union's common stock is no longer publicly traded.

Citrus Merger

In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion , consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units. See Note 4 for more information regarding ETP's equity method investment in Citrus.

In connection with the Citrus Merger, we relinquished our rights to an aggregate $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the merger.

Pursuant to the merger agreement, we also granted ETP a right of first offer with respect to any disposition by us or SUGS, a subsidiary of Southern Union that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the Southern Union Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet presented as of September 30, 2012 reflects the preliminary purchase price allocations based on available information. Certain amounts included in the preliminary purchase price allocation as of September 30, 2012 have been changed from amounts reflected as of March 31, 2012 based on management's review of the valuation. Management is continuing to validate certain assumptions made in connection with the purchase price allocation.

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The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:



Total current assets	$	561,038
Property, plant and equipment (useful lives of 25 - 30 years)	6,958,768
Goodwill	2,030,271
Intangible assets (weighted average useful life of 17.5 years)	55,000
Investments in unconsolidated affiliates	2,022,784
Other assets	162,576
	11,790,437

Long-term debt obligations, including current portion	3,778,706
Deferred income taxes	1,698,352
Other liabilities	950,513
	6,427,571
Total consideration	5,362,866
Cash received	36,792
Total consideration, net of cash received	$	5,326,074

Goodwill was allocated by reportable business segment as $1.17 billion to the Southern Union Transportation and Storage segment; $598.3 million to the Southern Union Gathering and Processing segment; $251.8 million to the Southern Union Distribution segment; and $10.8 million to Corporate and other.

Other liabilities assumed included approximately $46.0 million of AROs, which are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, Southern Union is legally or contractually required to abandon in place or remove the asset. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. Although a number of other onshore assets in Southern Union's system are subject to agreements that give rise to an ARO upon the discontinued use of the assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. As of September 30, 2012 AROs assumed as a result of the Southern Union Merger were approximately $46.4 million .

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2012 and 2011 are presented as if the Southern Union Merger had been completed on January 1, 2011. Actual results for the three months ended September 30, 2012 include Southern Union for the entire period.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Revenues	$	2,170,962		$	2,701,225	$	6,444,170	$	8,020,523
Net income	(33,834		)	78,831		1,139,241		431,326
Net income attributable to partners	35,170			80,430		390,147		268,536
Basic net income per Limited Partner unit	$	0.13		$	0.29	$	1.35	$	0.96
Diluted net income per Limited Partner unit	$	0.13		$	0.29	$	1.34	$	0.95

The pro forma consolidated results of operations include adjustments to:

• include the results of Southern Union for all periods presented;


•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;

• include incremental interest expense related to financing the transactions;

• adjust for one-time expenses; and

• adjust for relative changes in ownership resulting from the transactions.

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The pro forma information is not necessarily indicative of the results of operations that would have occurred had the Southern Union Merger been completed at the beginning of the periods presented or the future results of the combined operations.

Southern Union's revenue included in our consolidated statement of operations was approximately $477.9 million and $990.1 million for the three months ended September 30, 2012 and since the acquisition date to September 30, 2012 , respectively. Southern Union's net income included in our consolidated statement of operations was approximately $17.0 million for the three months ended September 30, 2012 and a net loss of $9.8 million since the acquisition date to September 30, 2012 , respectively.

Expenses Related to the Southern Union Merger

As a result of the acquisition, we recognized $38.2 million of merger-related costs during the nine months ended September 30, 2012 .

Sunoco Merger

On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and wholly-owned subsidiary of ETP, completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 54,971,724 ETP Common Units and a total of approximately $2.6 billion in cash.

Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32.4% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco's interest in Sunoco Logistics were transferred to ETP. In addition, in September 2012, Sunoco completed its exit from the refining business as a result of the contribution of its Philadelphia refinery to a joint venture and the related sale of its crude oil and refined product inventory to this joint venture. In connection with this transaction, Sunoco received a 33% non-operating minority interest in this joint venture.

Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in refined products pipelines. The crude oil pipeline business consists of crude oil pipelines, located principally in Oklahoma and Texas. The terminal facilities business consists of refined products and crude oil terminal capacity at the Nederland Terminal on the Gulf Coast of Texas and capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey. The crude oil acquisition and marketing business, principally conducted in Oklahoma and Texas, involves the acquisition and marketing of crude oil and consists of crude oil transport trucks and crude oil truck unloading facilities.

ETP incurred merger related costs related to the Sunoco Merger of $5.7 million and $12.0 million for the three and nine months ended September 30, 2012, respectively.

Holdco Transaction

Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE's contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 ETP Class F Units representing limited partner interests in ETP Class F Units. The ETP Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per ETP Class F Unit per year, which is ETP's current distribution level. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. Consequently, ETP will consolidate Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

Under the terms of the Holdco Transaction agreement, we relinquished an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The relinquishment applies to the distribution to be paid with respect to the quarter ended September 30, 2012.

Discontinued Operations

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assets and liabilities have been reclassified and reported as assets and liabilities held for sale as of September 30, 2012. A $145 million non-cash write-down of the carrying amounts of the Canyon assets to net recoverable value was recorded during the three months ended September 30, 2012.


4.	INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus Corp.

ETP acquired a 50% interest in Citrus, which owns 100% of FGT on March 26, 2012. A subsidiary of Kinder Morgan, Inc. owns the remaining 50% interest in Citrus. In exchange for the interest in Citrus, Southern Union received $1.9 billion in cash and $105.0 million of ETP Common Units. ETP initially recorded its investment in Citrus at $2.0 billion , which exceeded its proportionate share of Citrus' equity by $1.03 billion , all of which is treated as equity method goodwill due to the application of regulatory accounting.

AmeriGas Partners, L.P.

On January 12, 2012, ETP contributed its Propane Business to AmeriGas in exchange for approximately $1.46 billion in cash and approximately 29.6 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. In addition, AmeriGas assumed approximately $71.0 million of existing debt of the Propane Business. ETP recognized a gain on deconsolidation of $1.06 billion as a result of this transaction. ETP recorded equity in losses of $32.0 million and $28.9 million related to AmeriGas for the three and nine months ended September 30, 2012 , respectively.

ETP's investment in AmeriGas initially reflected $630.0 million in excess of the proportionate share of AmeriGas' limited partners' capital. Of this excess fair value, $288.6 million is being amortized over a weighted average period of 14 years and $341.4 million is being treated as equity method goodwill and non-amortizable intangible assets.

We have not reflected the Propane operations as discontinued operations as a result of ETP's investment in AmeriGas.

In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43.0 million .

Midcontinent Express Pipeline LLC

Regency owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in HPC, which, through its ownership of the RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.

Fayetteville Express Pipeline LLC

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 in Panola County, Mississippi.

Summarized Financial Information

The following table presents aggregated selected income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Revenue	$	869,162	$	803,085	$	3,280,285	$	2,767,669
Operating income	173,674		194,199		707,958		680,326
Net income	27,081		62,866		293,824		382,946

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In addition to the equity method investments described above, ETP, Regency and Southern Union each have other insignificant equity method investments.


5.	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.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2012		2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	432,330	$	154,378
Gain from subsidiary common unit transactions	$	32,592	$	93,941
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	1,123,003	$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger (see Note 3)	$	2,354,490	$	—
Subsidiary issuances of common units in connection with acquisitions	$	112,000	$	3,000
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	—	$	4,166


6.	INVENTORIES:

Inventories consisted of the following:



	September 30, 2012		December 31, 2011
Natural gas and NGLs, excluding propane	$	309,659	$	146,132
Propane	—		86,958
Appliances, parts and fittings and other	140,553		94,873
Total inventories	$	450,212	$	327,963

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.


7.	GOODWILL AND INTANGIBLE ASSETS:

A net increase in goodwill of $1.42 billion was recorded during the nine months ended September 30, 2012 , which includes goodwill of $2.03 billion recorded as a result of the Southern Union Merger partially offset by a decrease of $605.6 million as a result of ETP's contribution of its Propane Business to AmeriGas.

The goodwill recorded as a result of the Southern Union Merger was primarily due to expected commercial and operational synergies and is subject to change based on final purchase price allocations. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. See Note 3 for further discussion of Southern Union Merger.

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review goodwill and non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment

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test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations, as of November 30 for the Southern Union reporting units and as of December 31 for all others, including all of Regency’s reporting units. We have not completed our annual impairment tests for 2012 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2012.


8.	FAIR VALUE MEASUREMENTS:

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider 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. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of September 30, 2012 and December 31, 2011 was $19.73 billion and $12.21 billion , respectively. As of September 30, 2012 and December 31, 2011 , the aggregate carrying amount of our consolidated debt obligations was $18.14 billion and $11.37 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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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, 2012 and December 31, 2011 based on inputs used to derive their fair values:



	Fair Value Measurements at September 30, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities (included in other current assets)	$	6		$	6		$	—		$	—
Interest rate derivatives	54,479			—			54,479			—
Commodity derivatives:
Condensate — Forward Swaps	2,510			—			2,510			—
Natural Gas:
Basis Swaps IFERC/NYMEX	30,102			30,102			—			—
Swing Swaps IFERC	14,260			172			14,088			—
Fixed Swaps/Futures	87,887			84,383			3,504			—
Options — Calls	1,790			—			1,790			—
Options — Puts	2,322			—			2,322			—
Forward Physical Contracts	2,223			—			2,223			—
NGLs:
Swaps	8,250			—			8,250			—
Options — Puts	1,030			—			1,030			—
Power:
Forwards	6,176			—			6,176			—
Futures	374			374			—			—
Options — Calls	2,495			—			2,495			—
Total commodity derivatives	159,419			115,031			44,388			—
Total Assets	$	213,904		$	115,037		$	98,867		$	—
Liabilities:
Interest rate derivatives	$	(243,860	)	$	—		$	(243,860	)	$	—
Preferred Units	(327,960		)	—			—			(327,960		)
Embedded derivatives in the Regency Preferred Units	(29,094		)	—			—			(29,094		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(42,492		)	(42,492		)	—			—
Swing Swaps IFERC	(14,918		)	(648		)	(14,270		)	—
Fixed Swaps/Futures	(120,331		)	(104,316		)	(16,015		)	—
Options — Calls	(2,134		)	—			(2,134		)	—
Options — Puts	(672		)	—			(672		)	—
Forward Physical Contracts	(2,082		)	—			(2,082		)	—
NGLs — Swaps	(276		)	—			(276		)	—
Power:
Forwards	(5,865		)	—			(5,865		)	—
Futures	(605		)	(605		)	—			—
Options — Calls	(2,106		)				(2,106		)	—
Total commodity derivatives	(191,481		)	(148,061		)	(43,420		)	—
Total Liabilities	$	(792,395	)	$	(148,061	)	$	(287,280	)	$	(357,054	)

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	Fair Value Measurements at December 31, 2011
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities (included in other current assets)	$	1,229		$	1,229		$	—		$	—
Interest rate derivatives	36,301			—			36,301			—
Commodity derivatives:
Condensate — Forward Swaps	538			—			538			—
Natural Gas:
Basis Swaps IFERC/NYMEX	62,924			62,924			—			—
Swing Swaps IFERC	15,002			1,687			13,315			—
Fixed Swaps/Futures	218,479			214,572			3,907			—
Options — Puts	6,435			—			6,435			—
Forward Physical Contracts	699			—			699			—
NGLs:
Swaps	94			—			94			—
Options — Puts	309			—			309			—
Propane — Forwards/Swaps	9			—			9			—
Total commodity derivatives	304,489			279,183			25,306			—
Total Assets	$	342,019		$	280,412		$	61,607		$	—
Liabilities:
Interest rate derivatives	$	(117,490	)	$	—		$	(117,490	)	$	—
Preferred Units	(322,910		)	—			—			(322,910		)
Embedded derivatives in the Regency Preferred Units	(39,049		)	—			—			(39,049		)
Commodity derivatives:
Condensate — Forward Swaps	(1,567		)	—			(1,567		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82,290		)	(82,290		)	—			—
Swing Swaps IFERC	(16,074		)	(3,061		)	(13,013		)	—
Fixed Swaps/Futures	(148,111		)	(148,111		)	—			—
Options — Calls	(12		)	—			(12		)	—
Forward Physical Contracts	(712		)	—			(712		)	—
NGLs — Swaps	(8,561		)	—			(8,561		)	—
Propane — Forwards/Swaps	(4,131		)	—			(4,131		)	—
Total commodity derivatives	(261,458		)	(233,462		)	(27,996		)	—
Total Liabilities	$	(740,907	)	$	(233,462	)	$	(145,486	)	$	(361,959	)

The following table presents the material unobservable inputs used to estimate the fair value of the Preferred Units and the embedded derivatives in Regency's Preferred Units:



	Unobservable Input	September 30, 2012
Preferred Units	Assumed Yield	6.55	%
Embedded derivatives in the Regency Preferred Units	Credit Spread	6.31	%
	Volatility	18.32	%

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Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency's cost of equity and U. S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency's historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the nine months ended September 30, 2012 . There were no transfers between the fair value hierarchy levels during the nine months ended September 30, 2012 or 2011.



Balance, December 31, 2011	$	(361,959	)
Net unrealized gain included in other income (expense)	4,905
Balance, September 30, 2012	$	(357,054	)


9.	NET INCOME PER LIMITED PARTNER UNIT:

A reconciliation of net 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,
	2012			2011			2012			2011
Income from continuing operations	$	113,328		$	62,242		$	1,152,052		$	370,965
Less: Income (loss) from continuing operations attributable noncontrolling interest	(69,004		)	(8,384		)	746,900			142,435
Income from continuing operations, net of noncontrolling interest	182,332			70,626			405,152			228,530
Less: General Partner’s interest in income from continuing operations	451			219			1,121			707
Income from continuing operations available to Limited Partners	$	181,881		$	70,407		$	404,031		$	227,823
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	279,955,608			222,972,708			262,278,639			222,966,763
Basic income from continuing operations per Limited Partner unit	$	0.65		$	0.32		$	1.54		$	1.02
Basic loss from discontinued operations per Limited Partner unit	$	(0.53	)	$	(0.01	)	$	(0.57	)	$	(0.02	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	181,881		$	70,407		$	404,031		$	227,823
Dilutive effect of equity-based compensation of subsidiaries	—			(167		)	(1,235		)	(525		)
Diluted income from continuing operations available to Limited Partners	$	181,881		$	70,240		$	402,796		$	227,298
Weighted average Limited Partner units	279,955,608			222,972,708			262,278,639			222,966,763
Diluted income from continuing operations per Limited Partner unit	$	0.65		$	0.32		$	1.54		$	1.02
Diluted loss from discontinued operations per Limited Partner unit	$	(0.53	)	$	(0.01	)	$	(0.57	)	$	(0.02	)

The calculation above for the three and nine months ended September 30, 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because

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inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 11 .


10.	DEBT OBLIGATIONS:

Our debt obligations consisted of the following:



	September 30, 2012			December 31, 2011
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800,000		$	1,800,000
ETE Senior Secured Term Loan, due March 26, 2017	2,000,000			—
ETE Senior Secured Revolving Credit Facility	—			71,500
Subsidiary Indebtedness:
ETP Senior Notes (aggregated)	7,691,951			6,550,000
Transwestern Senior Unsecured Notes (aggregated)	870,000			870,000
HOLP Senior Secured Notes (aggregated)	—			71,314
Regency Senior Notes (aggregated)	1,262,429			1,350,000
Southern Union Senior Notes:
7.6% Senior Notes due February 1, 2024	359,765			—
8.25% Senior Notes due November 14, 2029	300,000			—
7.24% to 9.44% First Mortgage Bonds due February 15, 2020 to December 15, 2027	19,500			—
7.2% Junior Subordinated Notes due November 1, 2066	600,000			—
Notes Payable	7,306			—
Panhandle:
6.05% Senior Notes due August 15, 2013	250,000			—
6.2% Senior Notes due November 1, 2017	300,000			—
7.0% Senior Notes due June 15, 2018	400,000			—
8.125% Senior Notes due June 1, 2019	150,000			—
7.0% Senior Notes due July 15, 2029	66,305			—
Term Loan due February 23, 2015	455,000			—
Revolving Credit Facilities:
ETP Revolving Credit Facility	491,914			314,438
Regency Revolving Credit Facility	695,000			332,000
Southern Union Revolving Credit Facility	251,000			—
Other Long-Term Debt	20,140			10,434
Unamortized discounts, net	(53,962		)	(10,309		)
Fair value adjustments related to interest rate swaps	203,738			11,647
	18,140,086			11,371,024
Current maturities	(614,418		)	(424,160		)
	$	17,525,668		$	10,946,864

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $149.8 million in net unamortized discounts and fair value adjustments related to interest rate swaps:



2012 (remainder)	$	994
2013	604,154
2014	1,079,273
2015	1,209,557
2016	1,035,213
Thereafter	14,061,119
Total	$	17,990,310

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ETE Senior Secured Term Loan

We used the net proceeds from our Senior Secured Term Loan, along with proceeds received from ETP in the Citrus Merger, to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes.

Borrowings bear interest at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50% , and an adjusted one-month LIBOR rate plus 1.00% . The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of September 30, 2012 was 3.75% .

Southern Union Junior Subordinated Notes

Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175% . The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.46% at September 30, 2012 .

Panhandle Term Loans

In February 2012, Southern Union refinanced LNG Holdings' $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL's senior unsecured debt. The effective interest rate of PEPL's term loan was 1.84% at September 30, 2012 .

Bridge Term Loan Facility

Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated the 364-day Bridge Term Loan Facility. For the nine months ended September 30, 2012, bridge loan related fees reflects the recognition of $62.2 million of commitment fees upon termination of the facility.

ETP Senior Notes

In January 2012 ETP completed a public offering of $1.00 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1.00 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042 and used the net proceeds of $1.98 billion from the offering to fund the cash portion of the purchase price of the Citrus Merger and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest is paid semi-annually.

In January 2012 ETP announced a tender offer for approximately $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. The senior notes described below were repurchased under the offers for a total cost of $885.9 million and a loss on extinguishment of debt of $115.0 million was recorded during the nine months ended September 30, 2012 .

In the Any and All Offer ETP offered to purchase any and all of its 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, ETP purchased $292 million aggregate principal amount of its 5.65% Senior Notes due August 1, 2012.

In the Maximum Tender Offer ETP offered to purchase certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to the Maximum Tender Offer, on February 7, 2012, ETP purchased $200 million aggregate principal amount of its 9.7% Senior Notes due March 15, 2019, $200 million aggregate principal amount of its 9.0% Senior Notes due April 15, 2019 and $58.1 million aggregate principal amount of its 8.5% Senior Notes due April 15, 2014.

ETP as Co-Obligor of Sunoco Debt

In connection with the Sunoco Merger and Holdco Transaction, which was completed on October 5, 2012, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco's existing senior notes and debentures.

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Regency Senior Notes

In October 2012, Regency issued $700 million in senior notes that mature on April 15, 2023 (the “Regency Senior Notes Due 2023”). The Regency Senior Notes Due 2023 bear interest at 5.5% payable semi-annually in arrears on April 15 and October 15, commencing April 15, 2013. The proceeds were used to repay borrowings outstanding under the Regency Credit Facility.

In May 2012, Regency exercised its option to redeem 35% , or $87.5 million , of its outstanding senior notes due 2016 at a price of 109.375% .

Revolving Credit Facilities

Parent Company Credit Facility

As of September 30, 2012 , we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million .

ETP Credit Facility

As of September 30, 2012 , ETP had a balance of $491.9 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.98 billion after taking into account letters of credit of $31.9 million . The weighted average interest rate on the total amount outstanding as of September 30, 2012 was 1.72% .

ETP used approximately $2.0 billion of Sunoco's cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million , was funded with borrowings under the ETP Credit Facility.

Regency Credit Facility

In August 2012, Regency exercised the accordion feature of the Fifth Amended and Restated Credit Agreement (the "Credit Agreement") to increase its commitments under the Regency Credit Facility by $250 million to a total of $1.15 billion . The new commitments are available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the Credit Agreement. As of September 30, 2012 , there was a balance outstanding under the Regency Credit Facility of $695.0 million in revolving credit loans and approximately $8.6 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2012 , which was reduced by any letters of credit, was approximately $446.4 million , and the weighted average interest rate on the total amount outstanding as of September 30, 2012 was 2.72% .

Southern Union Credit Facilities

The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes. The weighted average interest rate on the total amount outstanding as of September 30, 2012 was 1.83% .

On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility. The amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.

Covenants Related to Our Credit Agreements

Covenants Related to Southern Union

Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Covenants exist in certain of the Southern Union’s debt agreements that require Southern Union to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

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Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:


•	Under the Southern Union Credit Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65% ;


•	Under the Southern Union Credit Facility, Southern Union must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;


•	Under Southern Union’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, Southern Union’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70% at the end of any calendar quarter; and


•	All of Southern Union’s major borrowing agreements contain cross-defaults if Southern Union defaults on an agreement involving at least $10 million of principal.

In addition to the above restrictions and default provisions, Southern Union and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2012 .


11.	REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

The Parent Company has outstanding 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. having an aggregate liquidation preference of $300 million . These units are reflected as a non-current liability in our consolidated balance sheets. The Preferred Units are measured at fair value on a recurring basis. Changes in the estimated fair value of the ETE Preferred Units are recorded in other income (expense) on our consolidated statements of operations.

Regency Preferred Units

Regency had 4,371,586 Regency Preferred Units outstanding at September 30, 2012 , which were convertible into 4,651,884 Regency Common Units. If outstanding on September 2, 2029 , the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s Partnership Agreement.


12.	EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the nine months ended September 30, 2012 was as follows:



	Number of Units
Outstanding at December 31, 2011	222,972,708
Issuance of restricted units under equity incentive plan	740
Issuance of common units in connection with Southern Union Merger (See Note 3)	56,982,160
Outstanding at September 30, 2012	279,955,608

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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, 2012 , we recognized increases in partners’ capital of $32.6 million .

Sales of Common Units by ETP

On July 3, 2012, ETP issued 15,525,000 ETP Common Units representing limited partner interests at $44.57 per ETP Common Unit in a public offering. Proceeds, net of commissions, of approximately $671.1 million from the offering were used to repay amounts outstanding under the ETP Credit Facility, to fund capital expenditures related to pipeline construction projects and for general partnership purposes.

During the nine months ended September 30, 2012 , ETP received proceeds from units issued pursuant to an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC of $76.7 million , net of commissions, which were used for general partnership purposes. No ETP Common Units remain available to be issued under the ETP Equity Distribution Agreement as of September 30, 2012 .

For the nine months ended September 30, 2012 , distributions of approximately $23.9 million were reinvested under ETP's DRIP resulting in the issuance of 548,708 ETP Common Units. As of September 30, 2012 , a total of 4,847,613 ETP Common Units remain available to be issued under this registration statement.

ETP issued approximately 2.25 million ETP Common Units to Southern Union as a portion of consideration in the Citrus Merger. See Note 3 for additional discussion.

Sale of Common Units by Regency

In March 2012, Regency issued 12,650,000 Regency Common Units through a public offering. The net proceeds of approximately $296.8 million were used to repay borrowings outstanding under the Regency Credit Facility and to redeem 35% in aggregate principal amount of its outstanding Senior Notes due 2016 and pay related premium expenses and interest.

On June 19, 2012, Regency entered into an Equity Distribution Agreement with Citi under which Regency may offer and sell Regency Common Units, having an aggregate offering price of up to $200 million from time to time through Citi, as sales agent for Regency. Sales of these units, if any, made under the Regency Equity Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and Citi. Under the terms of this agreement, Regency may also sell Regency Common Units to Citi as principal for its own account at a price agreed upon at the time of sale. Any sale of Regency Common Units to Citi as principal would be pursuant to the terms of a separate agreement between Regency and Citi. Regency intends to use the net proceeds from the sale of these units for general partnership purposes. During the nine months ended September 30, 2012 , Regency issued 691,129 Regency Common Units pursuant to its Equity Distribution Agreement with Citi and received net proceeds of $15.4 million .

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2011 :



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 7, 2012	February 17, 2012	$	0.625
March 31, 2012	May 4, 2012	May 18, 2012	0.625
June 30, 2012	August 6, 2012	August 17, 2012	0.625
September 30, 2012	November 6, 2012	November 16, 2012	0.625

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ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2011 :



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 7, 2012	February 14, 2012	$	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375
June 30, 2012	August 6, 2012	August 14, 2012	0.89375
September 30, 2012	November 6, 2012	November 14, 2012	0.89375

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2011 :



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 6, 2012	February 13, 2012	$	0.46
March 31, 2012	May 7, 2012	May 14, 2012	0.46
June 30, 2012	August 6, 2012	August 14, 2012	0.46
September 30, 2012	November 6, 2012	November 14, 2012	0.46

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	September 30, 2012			December 31, 2011
Net gains on commodity related hedges	$	1,014		$	1,696
Unrealized gains on available-for-sale securities	—			114
Equity investments, net	(13,771		)	—
Subtotal	(12,757		)	1,810
Amounts attributable to noncontrolling interest	7,010			(1,132		)
Total AOCI included in partners’ capital, net of tax	$	(5,747	)	$	678


13.	UNIT-BASED COMPENSATION PLANS:

We, ETP, and Regency 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, 2012 , no awards were granted to ETE employees. As of September 30, 2012 a total of 76,172 unit awards remain unvested, including the new awards granted to ETE directors during the period. We expect to recognize a total of $0.7 million in compensation expense over a weighted average period of 1.4 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the nine months ended September 30, 2012 , ETP employees were granted a total of 83,167 unvested awards with five -year service vesting requirements, and directors were granted a total of 6,760 unvested awards with three -year service vesting requirements. The weighted average grant-date fair value of these awards was $46.64 per unit. As of September 30, 2012 a total of 2,325,945 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize a total of $51.4 million in compensation expense over a weighted average period of 1.7 years related to unvested awards.

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Regency Unit-Based Compensation Plans

Common Unit Options

There was no Regency Common Unit Option activity for the nine months ended September 30, 2012 . The aggregate intrinsic value and weighted average contractual term in years as of September 30, 2012 for the outstanding and exercisable common unit options was $0.3 million and 3.6 years, respectively. During the nine months ended September 30, 2011 , Regency received $0.8 million in proceeds from the exercise of unit options.

Phantom Units

During the nine months ended September 30, 2012 , Regency employees and directors were granted 8,250 Regency phantom units with three -year service vesting requirements. As of September 30, 2012 , a total of 958,072 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.58 per unit. Regency expects to recognize a total of $16.3 million in compensation expense over a weighted average period of 3.6 years related to Regency’s unvested phantom units.


14.	BENEFITS:

Southern Union has pension plans that cover substantially all of its distribution operations' employees. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

Southern Union has other postretirement plans that cover most of its employees. The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the acquisition date (March 26, 2012) about the obligations and funded status of Southern Union’s pension and other postretirement plans on a combined basis:



	Pension Benefits			Other Postretirement Benefits
Benefit obligation	$	227,548		$	140,651
Fair value of plan assets	$	143,979		$	118,784
Amount underfunded	$	(83,569	)	$	(21,867	)
Amounts recognized in our consolidated balance sheet related to Southern Union's pension and other postretirement plans consist of:
Non-current assets	$	—		$	6,062
Current liabilities	—			(133		)
Non-current liabilities	(83,569		)	(27,796		)
	$	(83,569	)	$	(21,867	)

The following table summarizes information at the acquisition date (March 26, 2012) for plans with an accumulated benefit obligation in excess of the plan assets:



	Pension Benefits		Other Postretirement Benefits
Projected benefit obligation	$	227,548	N/A
Accumulated benefit obligation	213,614		$	110,314
Fair value of plan assets	143,979		82,385

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Assumptions

The following table includes weighted average assumptions used in determining benefit obligations as of the acquisition date (March 26, 2012):



	Pension Benefits		Other Postretirement Benefits
Discount rate	4.10	%	4.10	%
Rate of compensation increase	3.03	%	N/A

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union's other postretirement benefit plans as of the acquisition date (March 26, 2012) are shown in the table below:



Health care cost trend rate assumed for next year	9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.85	%
Year that the rate reaches the ultimate trend rate	2020

Defined Contribution Plan

Employees of Southern Union and its subsidiaries participate in a company-sponsored defined contribution savings plan that is substantially similar to the 401(k) savings plan that covers the employees of ETE, ETP and Regency.


15.	INCOME TAXES:

The components of the federal and state income tax expense of our taxable subsidiaries are summarized as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current expense (benefit):
Federal	$	(9,559	)	$	1,124		$	(9,619	)	$	6,787
State	4,794			2,675			12,683			12,107
Total	(4,765		)	3,799			3,064			18,894
Deferred expense (benefit):
Federal	31,475			(41		)	29,257			(599		)
State	1,915			(468		)	8,058			120
Total	33,390			(509		)	37,315			(479		)
Total income tax expense	$	28,625		$	3,290		$	40,379		$	18,415

Our effective tax rate has historically differed from the statutory rate primarily due to partnership earnings that are not subject to federal and state income taxes at the partnership level. The acquisition of Southern Union on March 26, 2012 increased our overall effective tax rate since Southern Union is a C-corporation and is subject to federal and state income taxes. We expect the acquisition of Sunoco to increase our effective tax rate in future periods since Sunoco is also a C-corporation and is subject to federal and state income taxes.

In connection with the Southern Union Merger, we recorded a net deferred tax liability of approximately $1.70 billion , which was primarily related to property, plant and equipment. Southern Union has deferred tax net operating loss carry forwards of $57.8 million as of September 30, 2012 , of which $17.6 million and $40.2 million expire in 2030 and 2031, respectively. Southern Union currently anticipates a federal net operating loss of $195.8 million for 2012.

As of September 30, 2012 , Southern Union has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $17.1 million , respectively, which relate to tax positions taken by Southern Union or its subsidiaries prior to our acquisition on March 26, 2012.

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16.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

Southern Union and its Subsidiaries

Sea Robin Pipeline, a subsidiary of Southern Union, is recovering Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, as well as applicable carrying charges, through a rate surcharge approved by the FERC. As of September 30, 2012 , our consolidated balance sheet reflects approximately $37.4 million of costs to be recovered by Sea Robin Pipeline in future periods via the surcharge.

The FERC is currently conducting an audit of PEPL, a subsidiary of Southern Union, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit is related to the period from January 1, 2010 through December 31, 2011 and is currently still in progress.

Contingent Residual Support Agreement — AmeriGas

AmeriGas Finance LLC, a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

In connection with ETP's contribution of its Propane Business, ETP entered into a CRSA with AmeriGas, AmeriGas Finance LLC, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt, as defined in the CRSA.

Commitments

In the normal course of our business, our operating entities purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on 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 2029 . Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $12.9 million and $7.3 million for the three months ended September 30, 2012 and 2011 , respectively, and $31.3 million and $20.5 million for the nine months ended September 30, 2012 and 2011 , respectively.

Future minimum lease commitments for such leases are:



Years Ending December 31:
2012 (remainder)	$	11,431
2013	41,244
2014	33,466
2015	31,917
2016	30,931
Thereafter	218,945

Certain of our subsidiaries' joint venture agreements require that they fund their proportionate shares of capital contributions to their unconsolidated affiliates. Such capital 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 NGLs are flammable, combustible gases. 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

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property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2012 and December 31, 2011 , accruals of approximately $9.3 million and $18.2 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.

No amounts have been recorded in our September 30, 2012 or December 31, 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Following is a discussion or our legal proceedings:

Will Price. Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On September 19, 2009, the Court denied plaintiffs’ request for class certification. Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010. Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC. As a result, Southern Union believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs). In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case. Southern Union believes it has no liability associated with this proceeding.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The Attorney General is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the Attorney General requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling $18.5 million , that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, Southern Union’s Vice Chairman, President and COO, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the Attorney General contends only would qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The Attorney General’s motion to be reimbursed for expert and consultant costs by Southern Union of up to $150,000 was granted. The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.

Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the New Mexico Environmental Department concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The New Mexico Environmental Department has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $0.5 million and at Jal #3 in the amount of $5.5 million. Hearings on the compliance orders were delayed to allow the parties to pursue substantive settlement discussions. SUGS has meritorious

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defenses to the New Mexico Environmental Department claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

FGT Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGT's mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $82.7 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGT's pipeline without the consent of FGT although FGT would be required to relocate the pipeline if it did not provide such consent. While FGT would seek reimbursement of any costs associated with relocation of its pipeline in connection with an FDOT project, FGT may not be successful in obtaining such reimbursement and, as such, could be required to bear the cost of such relocation. In any such instance, FGT would seek recovery of the reimbursement costs in rates. The judge also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. On June 6, 2012, Florida's Fourth District Court of Appeal (“4th DCA”) issued an opinion affirming the jury award of damages and also affirming or remanding for further consideration by the trial court certain other determinations with respect to FGT's easement rights and FDOT/FTE's obligations regarding future FDOT/FTE projects. In particular, the 4th DCA affirmed that FDOT/FTE could not pave directly over our pipeline without FBT's consent and remanded and directed the trial court to make reference in the final judgment to FDOT/FTE's obligation to seek reasonable alternatives to relocation. The 4th DCA did overturn the portion of the trial court judgment defining the width of FGT's easements as 15 feet on either side of its pipelines and defining the temporary work space available to Florida Gas under its easements as 75 feet in width, stating that the width of such easements and temporary work space should be determined on a case by case basis dependent on the needs of each particular relocation and whether a road improvement is a material interference with the easement. Reimbursement for any future relocation expenses will also be determined on a case by case basis. FGT has filed a petition requesting the Supreme Court of Florida to exercise its discretionary jurisdiction and to reverse the portion of the 4th DCA decision overturning the trial court judgment specifically defining the width of FGT's easements and temporary work space. The Supreme Court of Florida has not yet decided whether to hear the case. Amounts ultimately received would primarily reduce FGT's property, plant and equipment costs.

Litigation Relating to the Southern Union Merger

On June 21, 2011, a putative class action lawsuit captioned Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, was filed in the 333rd Judicial District Court of Harris County, Texas. Also on June 21, 2011, another putative class action lawsuit captioned Magda v. Southern Union Company, et al., Cause No. 2011-37134, was filed in the 11th Judicial District Court of Harris County, Texas. The petitions named as defendants the members of the Southern Union Board of Directors ("Southern Union Board"), as well as Southern Union and ETE. The petitions, which were also amended on June 28, 2011 and August 19, 2011, alleged that the Southern Union Board breached their fiduciary duties to Southern Union's stockholders in connection with the merger transaction with ETE and that Southern Union and ETE aided and abetted those alleged breaches. The petitions further alleged that the Southern Union Merger involved an unfair price and an inadequate sales process, that Southern Union's directors entered into the transaction to benefit themselves personally, including though consulting and noncompete agreements and that defendants have failed to disclose all material information related to the Southern Union Merger to Southern Union stockholders. The petition sought injunctive relief, including an injunction of the Southern Union Merger, and an award of attorneys' and other fees and costs, in addition to other relief. The two Texas cases have been consolidated with the following style: In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. 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 (described below).

On June 27, 2011, a putative class action lawsuit captioned Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS, was filed in the Delaware Court of Chancery. Additionally, on June 29 and 30, 2011, putative class action lawsuits captioned KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS, and LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS, respectively were filed in the Delaware Court of Chancery. Also, on July 6, 2011, a putative class action lawsuit captioned Memo v. Southern Union Company, et al., C.A. No. 6639-CS, was filed in the Delaware Court of Chancery. Each complaint named as defendants the members of the Southern Union Board, Southern Union, and ETE. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the merger transaction with ETE and further claimed that ETE aided and abetted those alleged breaches. The complaints further alleged that the Southern Union Merger involves an unfair price and an inadequate sales process, that Southern Union's directors entered into the transactions to benefit themselves personally, including through consulting and noncompete agreements, and

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that the Southern Union Board should deem a competing proposal made by The Williams Companies, Inc. to be superior. The complaints sought compensatory damages, injunctive relief, including an injunction of the Southern Union Merger, and an award of attorneys' and other fees and costs, in addition to other relief.

On August 25, 2011, a consolidated amended complaint was filed in the Southeastern Pennsylvania Transportation Authority, KBC Asset Management NV, and LBBW Asset Management Investment GmbH actions pending in the Delaware Court of Chancery naming the same defendants as the original complaints in those actions and alleging that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the merger transactions with ETE, that ETE aided and abetted those alleged breaches of fiduciary duty, and that the provisions in Section 5.4 of the Second Amended Merger Agreement relating to Southern Union's ability to accept a superior proposal is invalid under Delaware law. The amended complaint alleges that the Southern Union 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 the defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The consolidated amended complaint sought injunctive relief, including an injunction of the Southern Union Merger and an award of attorneys' and other fees and costs, in addition to other relief. The four Delaware Court of Chancery cases have been consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery.

On November 9, 2011, the attorneys for the plaintiffs in the aforementioned Texas and Delaware actions stated that they did not intend to pursue their efforts to enjoin the Southern Union Merger. Plaintiffs have indicated that they intend to pursue a claim for damages. A trial has not yet been scheduled in any of these matters. Discovery for the damages claim is in its preliminary stages.

On July 25, 2012, the plaintiffs in the Delaware action filed a notice with the Delaware Court of Chancery to voluntarily dismiss all claims without prejudice. In the notice, the plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case before the District Court of Harris County, Texas, 333rd Judicial District.

ETE has not recorded an accrued liability, believes the allegations of all the foregoing actions related to the Southern Union Merger lack merit, and intends to contest them vigorously.

In November, 2011, a derivative lawsuit captioned W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, was filed in the 234th Judicial District Court of Harris County, Texas. The petition stated that it was filed on behalf of ETP. ETP was also named as a nominal defendant. The petition also named as defendants ETP GP, ETP LLC, the Boards of Directors of ETP LLC (collectively with ETP GP, and ETP LLC, the "ETP Defendants"), ETE, and Southern Union. In October 2012, the plaintiff and two new unitholder plaintiffs filed their third amended petition, naming these same defendants and adding Royal Bank of Scotland, PLC, RBS Securities, Inc. ("RBS"), and four members of ETP management ("Management Defendants") as defendants. In their third amended petition, the plaintiffs allege that the ETP Defendants breached their fiduciary and contractual duties in connection with the Citrus Merger and ETP’s contribution of its Propane Business to AmeriGas (the "AmeriGas Transaction"). The third amended petition alleges that the Citrus Merger, among other things, involves an unfair price and an unfair process and that the ETP Defendants failed to adequately evaluate the transaction. The third amended petition also alleges that the ETP Defendants failed to, among other things, adequately evaluate the AmeriGas Transaction. The third amended petition alleges that these defendants entered into both transactions primarily to assist in ETE’s consummation of its merger with Southern Union and thereby primarily to benefit themselves personally. The third amended petition further alleges that RBS committed malpractice in issuing fairness opinions and that the Management Defendants failed to disclose material information regarding RBS' relationship with ETE. The third amended petition asserts claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and Management Defendants. The third amended petition asserts claims against ETE and Southern Union for aiding and abetting the breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith, as well as tortious interference with contract. The third amended petition also asserts claims for declaratory judgment and conspiracy against all defendants. The lawsuit seeks, among other things, the following relief: (i) a declaration that the lawsuit is properly maintainable as a derivative action; (ii) a declaration that the Citrus Merger and AmeriGas Transaction were unlawful and unenforceable because they involved breaches of fiduciary and contractual duties; (iii) a declaration that ETE and Southern Union aided and abetted the alleged breaches of fiduciary and contractual duties; (iv) a declaration that defendants conspired to breach, aided and abetted, and did breach fiduciary and contractual duties; (v) an order directing the ETP Defendants and Management Defendants to exercise their fiduciary duties to obtain a transaction or transactions in the best interest of ETP’s unitholders; (vi) damages; and (vii) attorneys’ and other fees and costs.

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In March 2012, this action was transferred to the 157 ^th Judicial District Court of Harris County, Texas. In October 2012, the defendants filed a motion for summary judgment; the court has not yet ruled on the motion. Trial in this action has been set for the first half of 2013.

Litigation Related to Sunoco Merger

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco's board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco's directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the merger. It is anticipated that the plaintiffs' attorneys will seek compensation for attorneys' fees related to their efforts in obtaining these additional disclosures; we currently are not able to estimate how much these fees will be.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities. We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Our subsidiaries have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage and to limit the financial liability which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our subsidiaries' liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future.

The EPA's Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require some of our subsidiaries to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule's requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule is required by October 2013.

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On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require some of our subsidiaries to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes our subsidiaries might make in the future, but we would not expect that the cost to comply with the rule's requirements will have a material adverse effect on our financial condition or results of operations.

On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. ETP is reviewing the new standards to determine the impact on its operations.

Our subsidiaries' pipeline operations are subject to regulation by the DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause our subsidiaries to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:


•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.


•	Southern Union's distribution operations are responsible for soil and groundwater remediation at certain sites related to MGPs and may also be responsible for the removal of old MGP structures.

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, 2012		December 31, 2011
Current	$	4,964	$	3,861
Non-current	32,809		9,990
Total environmental liabilities	$	37,773	$	13,851

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17.	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 will lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it 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 its 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 ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales in its interstate transportation operations. 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 our consolidated statements of operations.

ETP's trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to ETP's transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, ETP also has trading activities related to power in its "All Other" operations which are also netted in costs of products sold. As a result of ETP's trading activities and the use of derivative financial instruments in ETP's transportation and storage operations, 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 (i) the use of daily position and profit and loss reports provided to its risk oversight committee, which includes members of senior management, and (ii) the limits and authorizations set forth in ETP's commodity risk management policy.

Derivatives are utilized in ETP’s midstream operations 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. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. To the extent that financial contracts are not tied to physical delivery volumes, ETP may engage in offsetting financial contracts to balance its positions. To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.

Prior to the deconsolidation of the Propane Business, ETP also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts and to secure the purchase price of its propane inventory for a percentage of the anticipated sales by its cylinder exchange business.

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The following table details ETP’s outstanding commodity-related derivatives:



	September 30, 2012			December 31, 2011
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	(29,850,000	)	2012-2013	(151,260,000	)	2012-2013
Power (Megawatt):
Forwards	230,000		2012-2013	—		—
Futures	(14,500	)	2012	—		—
Options — Calls	1,535,600		2012-2013	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(8,057,500	)	2012-2013	(61,420,000	)	2012-2013
Swing Swaps IFERC	(18,827,500	)	2012-2013	92,370,000		2012-2013
Fixed Swaps/Futures	(2,992,500	)	2012-2014	797,500		2012
Forward Physical Contracts	(7,505,500	)	2012-2013	(10,672,028	)	2012
Propane (Gallons):
Forwards/Swaps	—		—	38,766,000		2012-2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(20,670,000	)	2012-2013	(28,752,500	)	2012
Fixed Swaps/Futures	(46,752,500	)	2012-2013	(45,822,500	)	2012
Hedged Item — Inventory	46,752,500		2012-2013	45,822,500		2012
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(4,600,000	)	2012-2013	—		—
Fixed Swaps/Futures	(11,900,000	)	2012-2013	—		—
Options — Puts	900,000		2012	3,600,000		2012
Options — Calls	(900,000	)	2012	(3,600,000	)	2012

⁽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 $4.1 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.

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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 effected by the inherent volatility of these commodities, which could adversely effect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Regency’s Preferred Units (see Note 11 ) contain embedded derivatives, such as the holders’ conversion option and Regency’s call option, which are required to be bifurcated and accounted for separately. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to effect its cash flows.

The following table details Regency’s outstanding commodity-related derivatives:



	September 30, 2012		December 31, 2011
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	5,748,000	2012-2014	—	—
Propane (Gallons):
Forwards/Swaps	6,972,000	2012-2013	—	—
Natural Gas Liquids (Barrels):
Forwards/Swaps	193,000	2012-2013	—	—
Options — Puts	78,000	2012	110,000	2012
WTI Crude Oil (Barrels):
Forwards/Swaps	415,000	2012-2014	—	—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	—	—	2,198,000	2012
Propane (Gallons):
Forwards/Swaps	—	—	11,802,000	2012-2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	—	—	533,000	2012-2013
WTI Crude Oil (Barrels):
Forwards/Swaps	—	—	350,000	2012-2014

On January 1, 2012, Regency de-designated all of its swap contracts and has accounted for these contracts using mark-to-market accounting. As of September 30, 2012 , Regency had $1.3 million in net hedging gains in AOCI which will be amortized to earnings over the next 1.5 years, of which $1.2 million will be reclassified into earnings over the next 12 months.

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Southern Union

Southern Union is exposed to certain commodity price risks in its ongoing business operations. Natural gas and NGL price swaps and NGL processing spread swaps are the principal derivative instruments used by Southern Union to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time.

Southern Union primarily enters into natural gas and NGL price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of equity natural gas and NGL volumes resulting from movements in market commodity prices.

Southern Union enters into natural gas commodity financial instruments to manage the exposure to changes in the cost of natural gas passed through to utility customers that result from movements in market commodity prices. The cost of the derivative instruments and settlement of the respective obligations are recovered from utility customers through the purchased natural gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.

The following table details Southern Union’s outstanding commodity-related derivatives:



	September 30, 2012
	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	18,430,000	2012-2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	12,797,500	2012-2013
Natural Gas Liquids (Barrels):
Fixed Swaps/Futures	2,319,300	2012

We expect net after-tax gains of $6.8 million related to Southern Union’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.

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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 is a summary of interest rate swaps outstanding as of September 30, 2012 and December 31, 2011 , none of which were designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type ⁽¹⁾

September 30,
2012

December 31, 2011

ETE

March 2017

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

500,000

—

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350,000

ETP

August 2012 ⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400,000

300,000

ETP

July 2014 ⁽²⁾

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400,000

—

ETP

July 2018

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

600,000

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

—

250,000

Southern Union

November 2016

Pay a fixed rate of 2.913% and receive a floating rate

75,000

N/A

Southern Union

November 2021

Pay a fixed rate of 3.746% and receive a floating rate

450,000

N/A

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


⁽²⁾	These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

As of September 30, 2012 , Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single or multiple counterparties.

Our counterparties consist primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on 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 the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. ETP had net deposits with counterparties of $38.0 million and $66.2 million as of September 30, 2012 and December 31, 2011 , respectively.

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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.

Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments. The aggregate fair value of Southern Union's derivative instruments with credit-risk-related contingent features that are in a net liability position at September 30, 2012 was $3.2 million .

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of consolidated derivative assets and liabilities as of September 30, 2012 and December 31, 2011 :



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2012		December 31, 2011		September 30, 2012			December 31, 2011
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	5,529	$	77,197	$	(16,209	)	$	(819	)
Commodity derivatives	6,589		4,539		—			(10,128		)
	12,118		81,736		(16,209		)	(10,947		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	135,448	$	227,337	$	(156,673	)	$	(251,268	)
Commodity derivatives	19,600		1,017		(19,210		)	(4,844		)
Interest rate derivatives	54,479		36,301		(243,860		)	(117,490		)
Embedded derivatives in Regency Preferred Units	—		—		(29,094		)	(39,049		)
	209,527		264,655		(448,837		)	(412,651		)
Total derivatives	$	221,645	$	346,391	$	(465,046	)	$	(423,598	)

The commodity derivatives (margin deposits) are recorded in other current assets on our consolidated balance sheets. The remainder of the non-exchange traded financial derivative instruments are recorded at fair value as price risk management assets or price risk management liabilities and are classified as either current or long-term depending on the anticipated settlement date. In addition to the derivatives above, as of September 30, 2012 current price risk management liabilities included approximately $6.6 million of option premiums that are being amortized through 2013.

The following tables summarize the amounts recognized with respect to consolidated derivative financial instruments for the periods presented:



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(8,956	)	$	16,414	$	16,316	$	9,291
Interest rate derivatives	(4,294		)	—		15,415		—
Total	$	(13,250	)	$	16,414	$	31,731	$	9,291

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	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended September 30,					Nine Months Ended September 30,
		2012		2011			2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	9,612	$	(166	)	$	25,199	$	12,793
Total		$	9,612	$	(166	)	$	25,199	$	12,793



	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Three Months Ended September 30,						Nine Months Ended September 30,
		2012			2011			2012			2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(63	)	$	(91	)	$	(17	)	$	98
Total		$	(63	)	$	(91	)	$	(17	)	$	98



	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,
		2012		2011			2012		2011
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	4,230	$	(3,559	)	$	28,887	$	18,732
Total		$	4,230	$	(3,559	)	$	28,887	$	18,732

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	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,
		2012			2011			2012			2011
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	4,196		$	—		$	(7,099	)	$	—
Commodity derivatives — Non-Trading	Cost of products sold	(22,150		)	9,056			(35,957		)	4,067
Interest rate derivatives	Losses on non-hedged interest rate derivatives	(6,118		)	(68,496		)	(23,296		)	(65,093		)
Embedded derivatives	Other income	1,550			15,230			9,955			20,755
Total		$	(22,522	)	$	(44,210	)	$	(56,397	)	$	(40,271	)


18.	RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

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 20).

Transactions between ETE's subsidiaries and Enterprise were previously considered to be related party transactions due to Enterprise's ownership of a portion of ETE's limited partner interests. During the three and nine months ended September 30, 2011, subsidiaries of ETE recorded sales to Enterprise and $284.3 million and $748.5 million , respectively, and purchases from Enterprise of $92.7 million and $355.8 million , respectively, all of which were related party transactions based on Enterprise's interests in ETE at the time of the transactions.

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19.	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, 2012		December 31, 2011
Deposits paid to vendors	$	85,644	$	66,231
Prepaid expenses and other	85,298		116,902
Total other current assets	$	170,942	$	183,133

Other Non-Current Assets, net

Other non-current assets, net consisted of the following:



	September 30, 2012		December 31, 2011
Unamortized financing costs (3 to 30 years)	$	154,035	$	132,375
Regulatory assets	216,535		88,993
Other	104,991		27,542
Total other non-current assets, net	$	475,561	$	248,910

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	September 30, 2012		December 31, 2011
Interest payable	$	291,988	$	204,182
Customer advances and deposits	49,858		100,525
Accrued capital expenditures	419,897		228,877
Accrued wages and benefits	71,929		80,205
Taxes payable other than income taxes	156,238		79,331
Income taxes payable	9,703		14,781
Other	130,915		56,011
Total accrued and other current liabilities	$	1,130,528	$	763,912


20.	REPORTABLE SEGMENTS:

Prior to the completion of the Sunoco Merger and Holdco Transaction on October 5, 2012, our principal operations included reportable segments as follows:

•

Investment in ETP — ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star, a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. Concurrent with the Parent Company's acquisition of Southern Union, ETP acquired a 50% interest in Citrus, which owns FGT (see Note 3).


•	Investment in Regency — Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency

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focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•

Southern Union Transportation and Storage — We own the Transportation and Storage segment through our wholly-owned subsidiary, Southern Union. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas and also provides LNG terminalling and regasification services. Its operations expand from the Gulf Coast region throughout the Midwest and Great Lakes regions.

•

Southern Union Gathering and Processing — We own the Gathering and Processing segment through our wholly-owned subsidiary, Southern Union. The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are located in West Texas and Southeast New Mexico.


•	Southern Union Distribution — We own the Distribution segment through our wholly-owned subsidiary, Southern Union. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

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.

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 and unconsolidated affiliates based on proportionate ownership. 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.

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The following tables present financial information by reportable segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property and plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Segment Adjusted EBITDA:
Investment in ETP	$	481,665		$	404,152		$	1,484,074		$	1,263,587
Investment in Regency	114,222			112,276			363,543			307,469
Southern Union Transportation and Storage	122,486			—			205,130			—
Southern Union Gathering and Processing	25,296			—			36,155			—
Southern Union Distribution	22,461			—			35,907			—
Corporate and Other	(13,773		)	(13,221		)	(63,897		)	(29,294		)
Total	752,357			503,207			2,060,912			1,541,762
Depreciation and amortization	(219,458		)	(151,429		)	(589,080		)	(426,216		)
Interest expense, net of interest capitalized	(237,802		)	(193,772		)	(732,387		)	(543,218		)
Bridge loan related fees	—			—			(62,241		)	—
Gain on deconsolidation of Propane Business	—			—			1,056,709			—
Losses on non-hedged interest rate derivatives	(6,118		)	(68,497		)	(23,296		)	(65,094		)
Non-cash unit-based compensation expense	(10,675		)	(11,344		)	(34,411		)	(34,429		)
Unrealized gains (losses) on commodity risk management activities	4,128			8,615			(42,869		)	21,362
Losses on extinguishments of debt	—			—			(122,844		)	—
Gain on curtailment of other postretirement benefit plans	—			—			15,332			—
Proportionate share of unconsolidated affiliates' interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(127,120		)	(29,832		)	(311,213		)	(87,253		)
Adjusted EBITDA attributable to discontinued operations	(4,760		)	(5,007		)	(15,183		)	(15,028		)
Other, net	(8,599		)	13,591			(6,998		)	(2,506		)
Income from continuing operations before income tax expense	$	141,953		$	65,532		$	1,192,431		$	389,380



	September 30, 2012			December 31, 2011
Total assets:
Investment in ETP	$	18,297,560		$	15,518,616
Investment in Regency	5,968,136			5,567,856
Southern Union Transportation and Storage	5,695,305			—
Southern Union Gathering and Processing	2,820,127			—
Southern Union Distribution	1,249,047			—
Corporate and Other	443,556			470,086
Adjustments and Eliminations	(876,132		)	(659,765		)
Total	$	33,597,599		$	20,896,793

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Related party transactions between our reportable segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues:
Investment in ETP:
Revenues from external customers	$	1,402,867		$	1,694,560		$	3,906,974		$	4,964,200
Intersegment revenues	17,607			6,903			33,788			29,780
	1,420,474			1,701,463			3,940,762			4,993,980
Investment in Regency:
Revenues from external customers	313,162			388,271			976,553			1,058,646
Intersegment revenues	720			1,996			7,204			5,371
	313,882			390,267			983,757			1,064,017
Southern Union Transportation and Storage:
Revenues from external customers	187,029			—			384,270			—
Intersegment revenues	1,452			—			2,903			—
	188,481			—			387,173			—
Southern Union Gathering and Processing:
Revenues from external customers	210,949			—			425,684			—
Intersegment revenues	2,433			—			4,531			—
	213,382			—			430,215			—
Southern Union Distribution:
Revenues from external customers	73,237			—			167,742			—
Intersegment revenues	—			—			—			—
	73,237			—			167,742			—
Corporate and Other:
Revenues from external customers	2,796			—			4,948			—
Intersegment revenues	—			—			—			—
	2,796			—			4,948			—
Adjustments and Eliminations:
Revenues from external customers	(19,078		)	1,183			(55,650		)	2,037
Intersegment revenues	(22,212		)	(8,899		)	(48,426		)	(35,151		)
Total revenues	$	2,170,962		$	2,084,014		$	5,810,521		$	6,024,883

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The following tables provide revenues, grouped by similar products and services, for our investments in ETP and Regency. These amounts include intersegment revenues for transactions between ETP, Regency and Southern Union.

Investment in ETP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Intrastate Transportation and Storage	$	502,562	$	617,244	$	1,401,595	$	1,849,575
Interstate Transportation	131,989		120,065		387,165		330,016
Midstream	549,197		551,393		1,437,487		1,455,017
NGL Transportation and Services	156,909		131,284		459,028		224,970
Retail Propane and Other Retail Propane Related	—		236,781		92,972		1,037,969
All Other	79,817		44,696		162,515		96,433
Total revenues	1,420,474		1,701,463		3,940,762		4,993,980
Less: Intersegment revenues	17,607		6,903		33,788		29,780
Revenues from external customers	$	1,402,867	$	1,694,560	$	3,906,974	$	4,964,200

Investment in Regency



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Gathering and Processing	$	262,087	$	339,273	$	832,354	$	908,448
Contract Compression	37,841		36,024		111,279		112,532
Contract Treating	8,707		10,573		25,230		29,848
Corporate and Others	5,247		4,397		14,894		13,189
Total revenues	313,882		390,267		983,757		1,064,017
Less: Intersegment revenues	720		1,996		7,204		5,371
Revenues from external customers	$	313,162	$	388,271	$	976,553	$	1,058,646

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21.	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, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	18,049		$	18,460
Accounts receivable from related companies	7,661			1,456
Note receivable from affiliate	167,259			—
Other current assets	118			714
Total current assets	193,087			20,630
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,136,654			2,225,572
INTANGIBLE ASSETS, net	19,775			—
GOODWILL	9,006			—
OTHER NON-CURRENT ASSETS, net	58,857			49,906
Total assets	$	6,417,379		$	2,296,108
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	9		$	174
Accounts payable to related companies	4,257			12,334
Interest payable	81,118			34,753
Price risk management liabilities	4,641			—
Accrued and other current liabilities	623			953
Current maturities of long-term debt	3,021			—
Total current liabilities	93,669			48,214
LONG-TERM DEBT, less current maturities	3,780,673			1,871,500
PREFERRED UNITS	327,960			322,910
OTHER NON-CURRENT LIABILITIES	17,168			—
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL:
General Partner	(161		)	321
Limited Partners	2,203,817			52,485
Accumulated other comprehensive income (loss)	(5,747		)	678
Total partners’ capital	2,197,909			53,484
Total liabilities and partners' capital	$	6,417,379		$	2,296,108

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(6,840	)	$	(11,667	)	$	(48,283	)	$	(25,546	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(64,001		)	(40,819		)	(170,275		)	(122,345		)
Bridge loan related fees	—			—			(62,241		)	—
Losses on non-hedged derivatives	(6,052		)	—			(15,149		)	—
Equity in earnings of affiliates	118,213			102,565			552,270			369,833
Other, net	(6,528		)	19,068			(1,568		)	2,256
INCOME BEFORE INCOME TAXES	34,792			69,147			254,754			224,198
Income tax expense (benefit)	(378		)	64			(336		)	190
NET INCOME	35,170			69,083			255,090			224,008
GENERAL PARTNER’S INTEREST IN NET INCOME	87			214			725			693
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	35,083		$	68,869		$	254,365		$	223,315

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STATEMENTS OF CASH FLOWS

(unaudited)



	Nine Months Ended September 30,
	2012			2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	405,737		$	384,733
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	(1,113,377		)	—
Contributions to affiliate	(445,000		)	—
Note receivable from affiliate	(221,217		)	—
Payments received on note receivable from affiliate	55,000			—
Net cash used in investing activities	(1,724,594		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,028,000			20,000
Principal payments on debt	(141,450		)	(20,000		)
Distributions to partners	(490,601		)	(385,806		)
Debt issuance costs	(77,503		)	—
Net cash provided by (used in) financing activities	1,318,446			(385,806		)
DECREASE IN CASH AND CASH EQUIVALENTS	(411		)	(1,073		)
CASH AND CASH EQUIVALENTS, beginning of period	18,460			27,247
CASH AND CASH EQUIVALENTS, end of period	$	18,049		$	26,174

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands)

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, 2011 filed with the SEC on February 22, 2012 . Additionally, Energy Transfer Partners, L.P., Regency Energy Partners LP and Southern Union Company electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number for each registrant and company website address is as follows:


•	ETP — SEC File No. 1-11727; website address: www.energytransfer.com


•	Regency — SEC File No. 1-35262; website address: www.regencyenergy.com


•	Southern Union — SEC File No. 01-6407; website address: www.sug.com

The information on these websites is not incorporated by reference into this report.

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to a variety of risks, uncertainties and assumptions. 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 — It em 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 and in “Part II — Other Information – Item 1A. Risk Factors” included in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012 and included in this report.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At September 30, 2012 , our interests in ETP and Regency consisted of:



	General Partner Interest (as a % of total partnership interest)		IDRs		Common Units	Limited Partner Ownership (as a % and net of any treasury units)
ETP	1.4	%	100	%	52,476,059	21	%
Regency	1.6	%	100	%	26,266,791	15	%

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. From the closing of the acquisition of Southern Union on March 26, 2012 until the closing of the Holdco Transaction on October 5, 2012, the Parent Company also generated cash flows through Southern Union, as a wholly-owned subsidiary. Subsequent to the closing of the Holdco Transaction on October 5, 2012, the Parent Company's cash flows will derive from its investments in ETP and Regency, as well as its direct ownership of 60% of Holdco. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. The Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries.

The following is a brief description of our operating entities prior to the completion of the Sunoco Merger and Holdco Transaction on October 5, 2012:

•

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•

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales, as well as the Permian Delaware basin. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•

RECENT DEVELOPMENTS

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 54,971,724 ETP Common Units and a total of approximately $2.6 billion in cash.

ETP used approximately $2.0 billion of Sunoco's cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings under the ETP Credit Facility.

Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32.4% of the outstanding common units of Sunoco Logistics. In addition, in September 2012, Sunoco completed its exit from the refining business as a result of the contribution of its Philadelphia refinery to a joint venture and the related sale of its crude oil and refined product inventory to this joint venture. In connection with this transaction, Sunoco received a 33% non-operating minority interest in this joint venture.

Holdco Transaction

Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE's contribution, ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 ETP Class F Units representing limited partner interests in ETP. The ETP Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per ETP Class F Unit per year, which is ETP's current distribution level. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. Consequently, ETP will consolidate Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction.

Under the terms of the Holdco transaction agreement, we have relinquished an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The relinquishment will apply to the distribution paid with respect to the quarter ended September 30, 2012.

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Discontinued Operations

In October 2012, ETP sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated to present Canyon's operations as discontinued operations. Canyon's assets and liabilities have been reclassified and reported as assets and liabilities held for sale as of September 30, 2012. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $145 million during the three months ended September 30, 2012.

Results of Operations

Prior to the completion of the Sunoco Merger and Holdco Transaction on October 5, 2012, our principal operations included reportable segments as follows:

•

Investment in Regency — Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•


•	Southern Union Distribution — We own the Distribution segment through our wholly-owned subsidiary, Southern Union. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

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, 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 and unconsolidated affiliates based on proportionate ownership. 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.

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Consolidated Results



	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Change			2012			2011			Change
Segment Adjusted EBITDA:
Investment in ETP	$	481,665		$	404,152		$	77,513		$	1,484,074		$	1,263,587		$	220,487
Investment in Regency	114,222			112,276			1,946			363,543			307,469			56,074
Southern Union Transportation and Storage	122,486			—			122,486			205,130			—			205,130
Southern Union Gathering and Processing	25,296			—			25,296			36,155			—			36,155
Southern Union Distribution	22,461			—			22,461			35,907			—			35,907
Corporate and Other	(13,773		)	(13,221		)	(552		)	(63,897		)	(29,294		)	(34,603		)
Total	752,357			503,207			249,150			2,060,912			1,541,762			519,150
Depreciation and amortization	(219,458		)	(151,429		)	(68,029		)	(589,080		)	(426,216		)	(162,864		)
Interest expense, net of interest capitalized	(237,802		)	(193,772		)	(44,030		)	(732,387		)	(543,218		)	(189,169		)
Bridge loan related fees	—			—			—			(62,241		)	—			(62,241		)
Gain on deconsolidation of Propane Business	—			—			—			1,056,709			—			1,056,709
Losses on non-hedged interest rate derivatives	(6,118		)	(68,497		)	62,379			(23,296		)	(65,094		)	41,798
Non-cash unit-based compensation expense	(10,675		)	(11,344		)	669			(34,411		)	(34,429		)	18
Unrealized gains (losses) on commodity risk management activities	4,128			8,615			(4,487		)	(42,869		)	21,362			(64,231		)
Losses on extinguishments of debt	—			—			—			(122,844		)	—			(122,844		)
Gain on curtailment of other postretirement benefit plans	—			—			—			15,332			—			15,332
Proportionate share of unconsolidated affiliates' interest, depreciation, amortization, non-cash compensation expense, loss on extinguishment of debt and taxes	(127,120		)	(29,832		)	(97,288		)	(311,213		)	(87,253		)	(223,960		)
Adjusted EBITDA attributable to discontinued operations	(4,760		)	(5,007		)	247			(15,183		)	(15,028		)	(155		)
Other, net	(8,599		)	13,591			(22,190		)	(6,998		)	(2,506		)	(4,492		)
Income from continuing operations before income tax expense	141,953			65,532			76,421			1,192,431			389,380			803,051
Income tax expense	(28,625		)	(3,290		)	(25,335		)	(40,379		)	(18,415		)	(21,964		)
Income from continuing operations	113,328			62,242			51,086			1,152,052			370,965			781,087
Loss from discontinued operations	(147,162		)	(1,543		)	(145,619		)	(150,062		)	(4,522		)	(145,540		)
Net income (loss)	$	(33,834	)	$	60,699		$	(94,533	)	$	1,001,990		$	366,443		$	635,547

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

Depreciation and Amortization. Depreciation and amortization increased for the three and nine months ended September 30, 2012 compared to the same periods in the prior year primarily due to the Southern Union Merger. For the three months ended September 30, 2012, ETE's consolidated financial statements reflected $75.7 million of depreciation and amortization recorded by Southern Union. For the nine months ended September 30, 2012, ETE's consolidated financial statements reflected $154.9 million of depreciation and amortization recorded by Southern Union subsequent to the merger on March 26, 2012. Depreciation and amortization also increased due to incremental depreciation from growth projects completed by ETP and Regency. These increases

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in depreciation and amortization were partially offset by the deconsolidation of ETP's Propane Business, which had recognized depreciation of $20.4 million and $62.2 million for three and nine months ended September 30, 2011, respectively.

Interest Expense, Net of Interest Capitalized. For the three months ended September 30, 2012 compared to the same period in the prior year, interest expense increased primarily due to the following:


•	An increase of $23.2 million for the Parent Company primarily related to the Parent Company's $2.0 billion Senior Secured Term Loan which was used to fund a portion of the cash consideration for the Southern Union Merger; and,


•	Southern Union's recognition of $34.6 million of interest expense during the period.

For the nine months ended September 30, 2012 compared to the same period in the prior year, interest expense increased primarily due to the following:


•	An increase of $47.9 million for the Parent Company primarily related to the Parent Company's $2.0 billion Senior Secured Term Loan which was used to fund a portion of the cash consideration for the Southern Union Merger;


•	An increase of $35.6 million for ETP primarily due to the issuance of $1.5 billion of senior notes in May 2011 and $2.0 billion of notes in January 2012 to fund acquisitions, the impacts of which were partially offset by a reduction of interest due to ETP's repurchase of $750 million of its senior notes in January 2012;


•	An increase of $12.5 million for Regency primarily due to its issuance of $500 million of senior notes in May 2011; and,


•	Southern Union's recognition of $96.3 million of interest expense during the post-acquisition period.

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

Losses on Non-Hedged Interest Rate Derivatives. The changes between the three and nine months ended September 30, 2012 compared to the same periods last year were primarily due to the recognition of losses in the prior year resulting from significant forward rate decreases from the global economic uncertainty at that time.

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

Losses on Extinguishments of Debt. ETP recognized a loss on extinguishment of debt for the nine months ended September 30, 2012 in connection with its repurchase of approximately $750 million in aggregate principal amount of senior notes in January 2012.

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

Income Tax Expense. The increase in income tax expense for the three and nine months ended September 30, 2012 compared to the same periods last year were primarily due to our acquisition of Southern Union in March 2012 which has a higher overall effective rate as Southern Union is subject to federal and state income taxes.

Supplemental Pro Forma Analysis

The table below presents unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2012 as if the Southern Union Merger had been completed on January 1, 2012.



	Nine Months Ended September 30, 2012
	Actual		Pro Forma
Revenues	$	5,810,521	$	6,444,170
Net income	1,001,990		1,139,241
Net income attributable to partners	255,090		390,147
Basic net income per Limited Partner unit	$	0.97	$	1.35
Diluted net income per Limited Partner unit	$	0.97	$	1.34

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The pro forma consolidated results of operations include adjustments to:


•	include the results of Southern Union for all periods presented;


•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;


•	include incremental interest expense related to financing the transactions;


•	adjust for one-time expenses; and


•	adjust for relative changes in ownership resulting from the transactions.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the period presented or the future results of the combined operations.

Segment Operating Results

Investment in ETP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Change			2012			2011			Change
Revenues	$	1,420,474		$	1,701,463		$	(280,989	)	$	3,940,762		$	4,993,980		$	(1,053,218	)
Cost of products sold	886,888			1,070,076			(183,188		)	2,319,318			3,067,316			(747,998		)
Gross margin	533,586			631,387			(97,801		)	1,621,444			1,926,664			(305,220		)
Unrealized losses (gains) on commodity risk management activities	(11,456		)	6,441			(17,897		)	59,519			(1,213		)	60,732
Operating expenses, excluding non-cash compensation expense	(99,133		)	(192,643		)	93,510			(348,064		)	(561,817		)	213,753
Selling, general and administrative, excluding non-cash compensation expense	(38,263		)	(48,117		)	9,854			(121,321		)	(128,961		)	7,640
Adjusted EBITDA attributable to unconsolidated affiliates	105,359			15,229			90,130			301,559			37,623			263,936
Adjusted EBITDA attributable to noncontrolling interest	(13,188		)	(13,152		)	(36		)	(44,246		)	(23,737		)	(20,509		)
Adjusted EBITDA attributable to discontinued operations	4,760			5,007			(247		)	15,183			15,028			155
Segment Adjusted EBITDA	$	481,665		$	404,152		$	77,513		$	1,484,074		$	1,263,587		$	220,487

Gross Margin . For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, ETP's gross margin decreased by $89.6 million and $398.9 million, respectively, due to ETP's deconsolidation of its Propane Business. For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, ETP's gross margin also decreased by $35.4 million and $117.0 million, respectively, as ETP's intrastate transportation and storage operations were primarily impacted by lower transported volumes and prices on transportation fees and retained fuel revenues. These decreases in ETP's gross margin were partially offset by favorable impacts from the acquisition of Lone Star in May 2011 and the expansion of Tiger pipeline which went into service in August 2011.

Unrealized Losses (Gains) on Commodity Risk Management Activities. ETP's unrealized losses on commodity risk management activities reflect the net impact from unrealized gains and losses on storage and non-storage derivatives as well as fair value adjustments on inventory. Unrealized gains increased for the three months ended September 30, 2012 primarily due to the impacts of fair value accounting as prices increased during the third quarter of 2012. During the three months ended September 30, 2012, ETP settled derivatives for a loss of $3.8 million. ETP also recorded additional mark-to-market gains of $6.0 million in the three months ended September 30, 2012 related to non-storage derivatives.

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Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, ETP's operating expenses decreased by $84.1 million and $227.2 million, respectively, due to the deconsolidation of ETP's Propane Business. These decreases were offset by increases in ETP's NGL transportation and services operations due to the acquisition of LDH by Lone Star in May 2011 and other NGL-related growth projects placed in service during the last nine months.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, lower selling, general and administrative expenses due to the deconsolidation of ETP's Propane Business were offset by increases in employee-related and other costs, including increases due to the acquisition of Lone Star in May 2011.

Adjusted EBITDA Attributable to Unconsolidated Affiliates. For the three months ended September 30, 2012 compared to the same period in the prior year, ETP's adjusted EBITDA attributable to unconsolidated affiliates increased primarily due to its acquisition of a 50% interest in Citrus on March 26, 2012. For the nine months ended September 30, 2012 compared to the same period in the prior year, the increase in ETP's adjusted EBITDA attributable to unconsolidated affiliates also reflected earnings from ETP's investment in AmeriGas, which was acquired in January 2012, in connection with the contribution of ETP's Propane Business.

Adjusted EBITDA Attributable to Noncontrolling Interest. These amounts represent the proportionate share of Lone Star's adjusted EBITDA attributable to Regency's 30% interest in Lone Star. This amount was excluded from the measure of Segment Adjusted EBITDA for ETP and was included in Regency's Segment Adjusted EBITDA within adjusted EBITDA attributable to unconsolidated affiliates. ETE's unconsolidated results of operations reflect 100% of Lone Star.

Investment in Regency



	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Change			2012			2011			Change
Revenues	$	313,882		$	390,267		$	(76,385	)	$	983,757		$	1,064,017		$	(80,260	)
Cost of products sold	206,881			279,526			(72,645		)	633,349			755,262			(121,913		)
Gross margin	107,001			110,741			(3,740		)	350,408			308,755			41,653
Unrealized losses (gains) on commodity risk management activities	7,327			(15,056		)	22,383			(16,650		)	(20,149		)	3,499
Operating expenses	(41,275		)	(37,950		)	(3,325		)	(121,248		)	(105,506		)	(15,742		)
Selling, general and administrative, excluding non-cash compensation expense	(13,759		)	(16,459		)	2,700			(43,636		)	(51,323		)	7,687
Adjusted EBITDA attributable to unconsolidated affiliates	54,201			56,128			(1,927		)	170,582			156,000			14,582
Other	727			14,872			(14,145		)	24,087			19,692			4,395
Segment Adjusted EBITDA	$	114,222		$	112,276		$	1,946		$	363,543		$	307,469		$	56,074

Gross Margin . For the three months ended September 30, 2012 compared to the same period in the prior year, Regency's gross margin decreased $3.7 million primarily due to Regency's non-cash mark-to-market losses on outstanding derivatives. For the nine months ended September 30, 2012 compared to the same period in the prior year, Regency's gross margin increased $41.7 million primarily due to increased volumes in Regency's West Texas and North Louisiana gathering and processing operations.

Unrealized Losses (Gains) on Commodity Risk Management Activities. For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, Regency's losses on commodity risk management activities increased primarily due to mark-to-market adjustments on its non-hedged commodity derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2012 compared to the same periods in the prior year, Regency's operating expenses, excluding non-cash compensation expense, increased $3.3 million and $15.7 million, respectively, primarily due to increased pipeline and plant operating activity in South and West Texas and increased compressor maintenance expense primarily due to increases in maintenance and materials costs.

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cash compensation expense, decreased $2.7 million and $7.7 million, respectively, primarily due to lower office expenses, legal fees, and insurance expense.

Adjusted EBITDA Attributable to Unconsolidated Affiliates. For the nine months ended September 30, 2012 compared to the same period in the prior year, Regency's adjusted EBITDA attributable to unconsolidated affiliates increased $14.6 million primarily due to the impact from Lone Star, which was formed in May 2011.

Other. The nine months ended September 30, 2012 reflected Regency's recognition of a $15.6 million one-time producer payment received in March 2012 related to an assignment of certain contracts. The three and nine months ended September 30, 2012 reflect lower non-cash mark-to-market gains on the embedded derivatives related to Regency's preferred units compared to the same periods in the prior year.

Southern Union Transportation and Storage

The Southern Union Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services. The segment’s operations, conducted through Panhandle are regulated as to rates and other matters by FERC. Demand for natural gas transmission services on Panhandle’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues and Segment Adjusted EBITDA occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011		Change			2012			2011		Change
Revenues	$	188,481		$	—	$	188,481		$	387,173		$	—	$	387,173
Operating expenses, excluding non-cash compensation expense, accretion and gain on curtailment	(60,181		)	—		(60,181		)	(159,486		)	—		(159,486		)
Taxes other than on income and revenues	(9,189		)	—		(9,189		)	(18,980		)	—		(18,980		)
Adjusted EBITDA attributable to unconsolidated affiliates	3,375			—		3,375			6,950			—		6,950
Net gain on curtailment of OPEB plans	—					—			(10,527		)	—		(10,527		)
Segment Adjusted EBITDA	$	122,486		$	—	$	122,486		$	205,130		$	—	$	205,130

The Southern Union transportation and storage segment was acquired through our acquisition of Southern Union on March 26, 2012; therefore, no comparative amounts were reflected in the prior periods.

Southern Union Gathering and Processing

The Southern Union Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs, and redelivering natural gas and NGLs to a variety of markets. Its operations are conducted through SUGS. SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts. These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years. SUGS’ primary sales customers include exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies. With respect to customer demand for the products and services it provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers can be adversely impacted by severe weather.

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	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011		Change			2012			2011		Change
Revenues	$	213,382		$	—	$	213,382		$	430,215		$	—	$	430,215
Cost of products sold	163,155			—		163,155			326,937			—		326,937
Gross margin	50,227			—		50,227			103,278			—		103,278
Operating expenses, excluding non-cash compensation expense	(23,195		)	—		(23,195		)	(63,510		)	—		(63,510		)
Taxes other than on income and revenues	(1,677		)	—		(1,677		)	(3,504		)	—		(3,504		)
Adjusted EBITDA attributable to unconsolidated affiliates	(59		)	—		(59		)	(109		)	—		(109		)
Segment Adjusted EBITDA	$	25,296		$	—	$	25,296		$	36,155		$	—	$	36,155

The Southern Union Gathering and Processing segment was acquired through our acquisition of Southern Union on March 26, 2012; therefore, no comparative amounts were reflected in the prior periods.

Southern Union Distribution

The Southern Union Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through Southern Union's Missouri Gas Energy and New England Gas Company operating divisions, respectively. The segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates. The segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues (which include pass-through gas purchase costs that are seasonally impacted) and Segment Adjusted EBITDA occurring in the traditional winter heating season during the first and fourth calendar quarters. Most of Missouri Gas Energy’s revenues are based on a distribution rate structure that eliminates the impact of weather and conservations.



	Three Months Ended September 30,								Nine Months Ended September 30,
	2012			2011		Change			2012			2011		Change
Revenues	$	73,237		$	—	$	73,237		$	167,742		$	—	$	167,742
Cost of products sold	20,543			—		20,543			53,300			—		53,300
Gross margin	52,694			—		52,694			114,442			—		114,442
Operating expenses, excluding non-cash compensation expense	(26,779		)	—		(26,779		)	(70,981		)	—		(70,981		)
Taxes other than on income and revenues	(3,454		)	—		(3,454		)	(7,554		)	—		(7,554		)
Segment Adjusted EBITDA	$	22,461		$	—	$	22,461		$	35,907		$	—	$	35,907

The Southern Union Distribution segment was acquired through our acquisition of Southern Union on March 26, 2012; therefore, no comparative amounts were reflected in the prior periods.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. From the closing of the acquisition of Southern Union on March 26, 2012 until the closing of the Holdco Transaction on October 5, 2012, the Parent Company also has generated cash flows through Southern Union, as a wholly-owned subsidiary. Subsequent to the closing of the Holdco Transaction on October 5, 2012, the Parent Company's cash flows will derive from its investments in ETP and Regency, as well as its direct ownership of 60% of Holdco. 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 the Citrus Merger, we have relinquished an aggregate $220 million of incentive distributions to be received from

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ETP over 16 consecutive quarters, approximately $13.8 million per quarter, beginning with the distribution paid in May 2012 for the quarter ended March 31, 2012. Also, in connection with the Holdco Transaction, we have relinquished an aggregate $210 million of incentive distributions to be received from ETP over 12 consecutive quarters, approximately $17.5 million per quarter, beginning with the distribution to be paid in November 2012 for the quarter ended September 30, 2012.

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

We issued a $2.0 billion Senior Secured Term Loan as permanent financing to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes. We also used a portion of the cash received from ETP in the Citrus Merger (discussed below) to fund the remaining cash portion of the Southern Union Merger.

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

ETP

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

ETP currently believes that its business has the following future capital requirements, which do not include capital requirements related to Holdco:


•	growth capital expenditures for its midstream and intrastate transportation and storage operations, primarily for construction of new pipelines and compression facilities, for which ETP expects to spend between $200 million and $225 million for the remainder of 2012 and between $350 million and $400 million for 2013;

•

growth capital expenditures for its NGL transportation and services operations of between $350 million and $400 million for the remainder of 2012 , for which ETP expects to receive capital contributions from Regency related to their 30% interest in Lone Star of between $100 million and $120 million. ETP also expects to spend between $400 million and $500 million in growth capital expenditures for its NGL transportation and services operations for 2013, for which it expects to receive capital contributions from Regency related to their 30% share of Lone Star of between $100 million and $150 million; and

•

maintenance capital expenditures of between $30 million and $40 million for the remainder of 2012, which include (i) capital expenditures for its intrastate operations for pipeline integrity and for connecting additional wells to its intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for its interstate operations, primarily for pipeline integrity; and (iii) capital expenditures related to NGL transportation and services, which includes amounts ETP expects to be funded by Regency related to its 30% interest in Lone Star. ETP also expects to spend between $125 million and $145 million in maintenance capital expenditures for 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. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time it experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by delays from mills, limited selection of mills capable of producing large diameter pipe in a timely manner, higher steel prices and other factors beyond ETP's control. However, ETP includes these factors in its anticipated growth capital expenditures for each year.

ETP generally funds its capital requirements with cash flows from operating activities, borrowings under its revolving credit facility, the issuance of long-term debt or common units or a combination thereof. Based on ETP's current estimates, it expects to utilize capacity under the ETP Credit Facility, along with cash from operations, to fund its announced growth capital expenditures and working capital needs for the next 12 months; 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.

ETP utilized the ETP Credit Facility to partially fund the cash portion of the Sunoco Merger consideration. ETP expect to continue to utilize the ETP Credit Facility to fund cash requirements; however, ETP expects to continue to prudently raise debt and equity

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to fund its growth capital requirements, to maintain sufficient liquidity, and to manage its credit metrics in order to maintain its investment grade credit ratings.

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.

Regency expects its growth capital expenditures to be between approximately $790 million and $840 million during 2012 , which includes $300 million for its gathering and processing operations, $100 million for its contract compression operations, $40 million for its contract treating operations, between $350 million and $400 million for its joint ventures (which consists of contributions to Lone Star). In addition, Regency expects its maintenance capital expenditures to be approximately $32 million during 2012 . Regency's total capital expenditures were $556.7 million and capital contributions to unconsolidated affiliates were $285.9 million for the nine months ended September 30, 2012. Regency has not publicly announced its expected capital expenditures for 2013.

In 2013, Regency expects to invest $400 million in growth capital expenditures, of which $185 million is expected to be invested in organic growth projects in the gathering and processing operations; $120 million is expected to be invested in Regency's portion of growth capital expenditures for Lone Star; $80 million is expected to be invested in the fabrication of new compressor packages for Regency's contract compression operations; and $15 million is expected to be invested in the fabrication of new treating plants for Regency's contract treating operations. In addition, Regency expects to invest $35 million in maintenance capital expenditures in 2013, including its proportionate share related to joint ventures.

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.

Southern Union

Cash generated from internal operations constitutes Southern Union's primary source of liquidity. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various capital markets and bank debt financings and proceeds from asset dispositions. The availability and terms relating to such liquidity will depend upon various factors and conditions such as Southern Union's combined cash flow and earnings, its resulting capital structure and conditions in the financial markets at the time of such offerings.

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.

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Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011 . Cash provided by operating activities during 2012 was $897.2 million as compared to $1.10 billion for 2011 . Net income was $1.0 billion and $366.4 million for 2012 and 2011 , respectively. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $138.1 million and $413.1 million and changes in operating assets and liabilities of $119.8 million and $234.2 million for 2012 and 2011 , respectively.

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 $122.8 million , the write-down of the Canyon assets of $145.2 million and the bridge loan related fees of $62.2 million which were not reflected in 2011. In addition, depreciation and amortization was $589.1 million and $426.2 million for 2012 and 2011 , respectively.

Cash paid for interest, net of interest capitalized, was $695.6 million and $489.6 million for the nine months ended September 30, 2012 and 2011 , respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, cash contributions to joint ventures, and cash proceeds from the contribution of ETP's Propane Business. 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, 2012 Compared to Nine Months Ended September 30, 2011 . Cash used in investing activities during 2012 was $3.61 billion as compared to $3.34 billion for 2011 . In 2012 , we paid cash for acquisitions of $2.98 billion , which primarily consisted of our acquisition of Southern Union for $2.97 billion . In 2011, we paid cash for acquisitions of $1.97 billion , which primarily consisted of ETP's acquisition of Lone Star. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2012 were $2.24 billion , including changes in accruals of $231.1 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2011 of $1.23 billion , including changes in accruals of $28.5 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, 2012 Compared to Nine Months Ended September 30, 2011 . Cash provided by financing activities during 2012 was $2.76 billion as compared to cash used in financing activities of $2.31 billion for 2011 . In 2012 , ETP received $771.8 million in net proceeds from offerings of ETP Common Units, including $76.7 million under ETP’s equity distribution program (see Note 12 to our consolidated financial statements), as compared to $799.3 million in 2011 . In 2012, Regency also received $312.2 million in net proceeds from its issuances of Regency Common Units. During 2012 , we had a consolidated net increase in our debt level of $2.94 billion as compared to a net increase of $2.30 billion for 2011 . We paid distributions of $490.6 million and $385.8 million to our partners in 2012 and in 2011 , respectively. In addition, during 2012 and 2011 , ETP paid distributions of $493.9 million and $417.2 million, respectively, on limited partner interests other than those held by the Parent Company. During 2012 and 2011 , Regency paid distributions of $194.0 million and $157.1 million, respectively, on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interest on our consolidated statements of cash flows.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	September 30, 2012			December 31, 2011
Parent Company Indebtedness:
ETE Senior Notes	$	1,800,000		$	1,800,000
ETE Senior Secured Term Loan	2,000,000			—
ETE Senior Secured Revolving Credit Facility	—			71,500
Subsidiary Indebtedness:
ETP Senior Notes	7,691,951			6,550,000
Regency Senior Notes	1,262,429			1,350,000
Southern Union Senior Notes	1,286,571			—
Panhandle Senior Notes	1,621,305			—
Transwestern Senior Unsecured Notes	870,000			870,000
HOLP Senior Secured Notes	—			71,314
ETP Revolving Credit Facility	491,914			314,438
Regency Revolving Credit Facility	695,000			332,000
Southern Union Revolving Credit Facility	251,000			—
Other long-term debt	20,140			10,434
Unamortized discounts, net	(53,962		)	(10,309		)
Fair value adjustments related to interest rate swaps	203,738			11,647
Total debt	18,140,086			11,371,024
Less: current maturities	(614,418		)	(424,160		)
Long-term debt, less current maturities	$	17,525,668		$	10,946,864

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, 2011 , filed with the SEC on February 22, 2012 and in Note 10 to our consolidated financial statements. As a result of the Southern Union Merger, we incurred additional indebtedness which is summarized below.

ETE Senior Secured Term Loan

Borrowings bear interest, at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of September 30, 2012 was 3.75% .

Southern Union Junior Subordinated Notes

Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.46% at September 30, 2012 .

Panhandle Term Loans

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Bridge Term Loan Facility

Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated the 364-day Bridge Term Loan Facility. For the nine months ended September 30, 2012, bridge loan related fees reflects $62.2 million representing amortization of the related commitment fees and write-off of the unamortized portion upon termination of the facility.

ETP Senior Notes

In January 2012, ETP completed a public offering of $1.0 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1.0 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042. ETP used the net proceeds of $1.98 billion from the offering to fund the cash portion of the purchase price of the Citrus Merger and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

In January 2012, ETP completed a cash tender offer for approximately $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. The senior notes described below were repurchased under the offers for a total cost of $885.9 million and a loss on extinguishment of $115.0 million was recorded during the nine months ended September 30, 2012 .

In the Any and All Offer, ETP offered to purchase, under certain conditions, any and all of its 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, ETP purchased $292 million in aggregate principal amount on January 19, 2012.

In the Maximum Tender Offer, ETP offered to purchase, under certain conditions, certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to this tender offer, on February 7, 2012, ETP purchased $200 million aggregate principal amount of its 9.7% Senior Notes due March 15, 2019, $200 million aggregate principal amount of its 9.0% Senior Notes due April 15, 2019 and $58.1 million aggregate principal amount of its 8.5% Senior Notes due April 15, 2014.

ETP As Co-Obligor of Sunoco Debt

Regency Senior Notes

In May 2012, Regency exercised its option to redeem 35% , or $87.5 million , of its outstanding senior notes due 2016 at a price of 109.375% .

Revolving Credit Facilities

Parent Company Credit Facility. As of September 30, 2012 , we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million .

ETP Credit Facility. As of September 30, 2012 , ETP had a balance of $491.9 million outstanding under the ETP Credit Facility, and the amount available under the ETP Credit Facility was $1.98 billion , after taking into account letters of credit of $31.9 million . The weighted average interest rate on the total amount outstanding at September 30, 2012 was 1.72% .

ETP used approximately $2.0 billion of Sunoco's cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings under the ETP Credit Facility.

Regency Credit Facility. In August 2012, RGS exercised the accordion feature of the Fifth Amended and Restated Credit Agreement (the "Credit Agreement") to increase its commitments under the revolving credit facility by $250 million to a total of $1.15 billion . The new commitments will be available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the Credit Agreement. As of September 30, 2012 , there was a balance outstanding under the Regency Credit Facility of $695.0 million in revolving credit loans and approximately $8.6 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2012 , which is reduced by any letters of credit, was approximately $446.4 million . The weighted average interest rate on the total amount outstanding as of September 30, 2012 was 2.72% .

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Southern Union Credit Facilities. The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings on the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes. The weighted average interest rate on the total amount outstanding as of September 30, 2012 was 1.83% .

Covenants Related to Our Credit Agreements

Covenants Related to Southern Union


•	Under the Southern Union Credit Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65%;


•	Under the Southern Union Credit Facility, Southern Union must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;


•	Under Southern Union’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, Southern Union’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70% at the end of any calendar quarter; and


•	All of Southern Union’s major borrowing agreements contain cross-defaults if Southern Union defaults on an agreement involving at least $10 million of principal.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2012 .

Contingent Residual Support Agreement — AmeriGas

AmeriGas Finance LLC, a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% Senior Notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% Senior Notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

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In connection with the Propane Contribution, ETP entered into and delivered a CRSA with AmeriGas, AmeriGas Finance LLC, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt, as defined in the CRSA.

Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of September 30, 2012 (in thousands):



	Payments Due by Period
Contractual Obligations	Total		Remainder of 2012		2013-2014		2015-2016		Thereafter
Long-term debt	$	17,990,310	$	994	$	1,683,427	$	2,244,770	$	14,061,119
Interest on long-term debt ^(a)	11,833,730		289,990		2,037,401		1,831,234		7,675,105
Payments on derivatives	88,419		6,869		73,003		—		8,547
Purchase commitments ^(b)	1,017,961		308,569		326,374		259,925		123,093
Lease obligations	367,934		11,431		74,710		62,848		218,945
Distributions and redemption of preferred units ^(c)	275,533		7,945		49,097		15,563		202,928
Other	23,794		1,153		9,056		8,838		4,747
Totals ^(d)	$	31,597,681	$	626,951	$	4,253,068	$	4,423,178	$	22,294,484

^(a)

Interest payments on long-term debt are based on the principal amount of debt obligations as of September 30, 2012 . With respect to variable rate debt, the interest payments were estimated using the interest rate as of September 30, 2012 . To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

^(b)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the September 30, 2012 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.


^(c)	Assumes the Preferred Units are converted to ETE Common Units on May 26, 2014 and assumes the Regency Preferred Units are redeemed for cash on September 2, 2029.


^(d)	Excludes net non-current deferred tax liabilities of $1.95 billion due to uncertainty of the timing of future cash flows for such liabilities.

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.

Following are distributions declared and/or paid by us subsequent to December 31, 2011 :

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Quarter Ended	Record Date	Payment Date	Rate

December 31, 2011	February 7, 2012	February 17, 2012	$	0.625
March 31, 2012	May 4, 2012	May 18, 2012	0.625
June 30, 2012	August 6, 2012	August 17, 2012	0.625
September 30, 2012	November 6, 2012	November 16, 2012	0.625

The total amounts of distributions declared and/or paid during the nine months ended September 30, 2012 and 2011 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,
	2012		2011
Limited Partners	$	524,916	$	403,564
General Partner interest	1,298		1,254
Total Parent Company distributions	$	526,214	$	404,818

Cash Distributions Received from Subsidiaries

In addition to the cash flows generated through its wholly-owned subsidiary, Southern Union, 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,
	2012		2011
Distributions from ETP:
Limited Partners ⁽¹⁾	$	134,671	$	134,670
General Partner interest	14,768		14,690
IDRs ⁽²⁾	322,737		310,254
Total distributions from ETP ⁽³⁾	472,176		459,614
Distributions from Regency:
Limited Partners	36,248		35,460
General Partner interest	3,968		3,861
IDRs	6,231		4,133
Total distributions from Regency	46,447		43,454
Total distributions received from subsidiaries	$	518,623	$	503,068


⁽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⁾

In connection with the Citrus Merger, we relinquished $220 million of incentive distributions to be received from ETP over 16 consecutive quarters, approximately $13.8 million per quarter. Also, in connection with the Holdco Transaction, we relinquished $210 million of incentive distributions to be received from ETP over 12 consecutive quarters, approximately $17.5 million per quarter. Accordingly, the distributions reflected above for the nine months ended September 30, 2012 reflect incentive distributions reductions totaling $58.8 million.


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

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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, 2011 :



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2011	February 7, 2012	February 14, 2012	$	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375
June 30, 2012	August 6, 2012	August 14, 2012	0.89375
September 30, 2012	November 6, 2012	November 14, 2012	0.89375

The total amounts of ETP distributions declared and/or paid during the nine months ended September 30, 2012 and 2011 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,
	2012		2011
Limited Partners:
Common Units	$	693,089	$	560,281
Class E Units ⁽¹⁾	9,363		9,363
Class F Units ⁽¹⁾	85,037		—
General Partner interest	14,768		14,690
IDRs	322,737		310,254
Total ETP distributions	$	1,124,994	$	894,588


⁽¹⁾	Total distributions to be paid in November 2012 on the Class E Units and Class F Units are $3.1 million and $85.0 million, respectively. All of the outstanding Class E Units and Class F Units are held by subsidiaries of Holdco, which is 60% owned by ETE subsequent to October 5, 2012.

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to December 31, 2011 :



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 6, 2012	February 13, 2012	$	0.46
March 31, 2012	May 7, 2012	May 14, 2012	0.46
June 30, 2012	August 6, 2012	August 14, 2012	0.46
September 30, 2012	November 6, 2012	November 14, 2012	0.46

The total amounts of Regency distributions declared and/or paid during the nine months ended September 30, 2012 and 2011 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,
	2012		2011
Limited Partners	$	235,070	$	203,114
General Partner interest	3,968		3,861
IDRs	6,231		4,133
Total Regency distributions	$	245,269	$	211,108

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CRITICAL ACCOUNTING POLICIES

As a result of the Southern Union Merger on March 26, 2012 , the following significant accounting policy has been added to our critical accounting policies described in our Form 10-K for the year ended December 31, 2011.

Pensions and Other Postretirement Benefit Plans

The Partnership is required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Partnership recognizes the changes in the funded status of its defined benefit postretirement plans through AOCI.

The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The discount rate is established by using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.

The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.

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, 2011 , 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, 2011 , other than additional primary market risk exposures related to the Southern Union Merger. Other than changes due to the Southern Union Merger, there have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2011 .

The United States Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173) in 2010, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. This legislation requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On August 13, 2012, the CFTC and SEC published their joint, final rules further defining the term “swap” for purposes of the Dodd-Frank Act. The final swap definition rules became effective on October 12, 2012, which, in turn, triggered several other compliance dates. However, the CFTC's swaps and futures position limit rules, which were expected to become effective on October 12, 2012, were vacated in a federal District Court decision and will no longer be in effect until the CFTC issues and finalizes revised rules. At this time, there is no pending proposal and no anticipated compliance date for CFTC position limit rules. In addition, in early October 2012, the CFTC issued numerous statements extending and clarifying compliance dates, and, as a result, many regulations, particularly those associated with new entities such as swap dealers and major swap participants, will become effective on December 31, 2012. Among other things, the October 12, 2012 date triggers the start of certain reporting and recordkeeping rules, with full compliance phased in over an additional 180-day period depending on swap asset class and counterparty. It is expected that entities that are end users of swaps or otherwise are not swap dealers or major swap participants will be required to comply with the Dodd-Frank reporting and recordkeeping rules in April 2013. The financial reform legislation may also require us to comply with swaps margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. Furthermore, some standardized swaps derivatives traded on organized markets are anticipated to be converted to futures contracts; while such futures transactions will not be subject to swaps regulations, they will be subject to regulation as futures transactions. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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, 2012 and December 31, 2011 .

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 portfolios 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.

ETP

Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and gallons for propane. Dollar amounts are presented in thousands.



	September 30, 2012							December 31, 2011
	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
(Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX ⁽¹⁾	(29,850,000	)	$	(10,528	)	$	261	(151,260,000	)	$	(22,582	)	$	2,593
Power:
Forwards	230,000		311			186		—		—			—
Futures	(14,500	)	(231		)	59
Options — Calls	1,535,600		388			917		—		—			—
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(8,057,500	)	(1,347		)	11		(61,420,000	)	4,024			266
Swing Swaps IFERC	(18,827,500	)	(658		)	541		92,370,000		(1,072		)	138
Fixed Swaps/Futures	(2,992,500	)	(1,247		)	1,344		797,500		(4,301		)	145
Forward Physical Contracts	(7,505,500	)	141			2,933		(10,672,028	)	(13		)	1,118
Options — Puts/Calls ⁽²⁾	—		(236		)	169		—		—			—
Propane:
Forwards/Swaps	—		—			—		38,766,000		(4,122		)	5,290
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(20,670,000	)	(449		)	120		(28,752,500	)	(808		)	181
Fixed Swaps/Futures	(46,752,500	)	(13,583		)	17,326		(45,822,500	)	70,761			14,048
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(4,600,000	)	(65		)	26		—		—			—
Fixed Swaps/Futures	(11,900,000	)	1,876			4,333		—		—			—
Options — Puts	900,000		1,543			197		3,600,000		6,435			933
Options — Calls	(900,000	)	—			—		(3,600,000	)	(12		)	13

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


⁽²⁾	Options were bought and sold at varying strike prices in offsetting volumes.

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 thousands.



	September 30, 2012					December 31, 2011
	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	5,748,000	$	315	$	2,198	—	$	—		$	—
Propane:
Forwards/Swaps	6,972,000	1,673		648		—	—			—
NGLs:
Forwards/Swaps	193,000	1,978		1,269		—	—			—
Options — Puts	78,000	1,030		103		110,000	309			113
WTI Crude Oil:
Forwards/Swaps	415,000	2,510		3,874		—	—			—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas:
Fixed Swaps/Futures	—	—		—		2,198,000	$	3,907		$	717
Propane:
Forwards/Swaps	—	—		—		11,802,000	(2,488		)	1,588
NGLs:
Forwards/Swaps	—	—		—		533,000	(5,979		)	2,956
WTI Crude Oil:
Forwards/Swaps	—	—		—		350,000	(1,029		)	3,429

Regency, for accounting purposes, de-designated its swap contracts on January 1, 2012 and is accounting for these contracts using mark-to-market accounting.

Southern Union

The following table summarizes SUGS' principal derivative instruments as of September 30, 2012 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes. Notional volumes are presented in MMBtu for natural gas and barrels for NGLs.



	September 30, 2012
	Notional Volume	Fair Value Asset (Liability)			Effect of Hypothetical Change ⁽¹⁾
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas:
Fixed Swaps/Futures	12,797,500	$	(5,480	)	$	12,309
Natural Gas Liquids:
Fixed Swaps/Futures	2,319,300	4,323			1,250


⁽¹⁾	Represents the impact on annual gross margin of a change in price of $0.01 per gallon of NGL and $1.00 per MMBtu of natural gas, excluding the effects of hedging and assuming normal operating conditions.

Interest Rate Risk

As of September 30, 2012 , we and our subsidiaries had $4.49 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $44.9 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, 2012 and December 31, 2011 (dollars in thousands), none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type ⁽¹⁾

September 30, 2012

December 31, 2011

ETE

March 2017

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

500,000

—

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350,000

ETP

August 2012 ⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400,000

300,000

ETP

July 2014 ⁽²⁾

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400,000

—

ETP

July 2018

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

600,000

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

—

250,000

Southern Union

November 2021

Pay a fixed rate of 2.913% and receive a floating rate

75,000

N/A

Southern Union

November 2016

Pay a fixed rate of 3.746% and receive a floating rate

450,000

N/A


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


⁽²⁾	These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

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 non-hedged interest rate derivatives) of approximately $120.4 million as of September 30, 2012 and $83.3 million as of December 31, 2011 . For ETP’s $600 million of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow (swap settlements) of $6.0 million. For ETP’s 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.

Credit Risk

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.

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 sheet and recognized in net income or other comprehensive income.

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, 2012 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

We closed the Southern Union Merger on March 26, 2012 and continue the evaluation and integration of the internal control structure of Southern Union. Certain of Southern Union's internal controls over financial reporting, including disclosure controls and corporate governance procedures, have already been impacted by changes made to conform to the existing controls and procedures of ETE.

None of the changes resulting from the Southern Union Merger were in response to any identified deficiency or weakness in our internal control over financial reporting. Other than changes resulting from the Southern Union Merger, 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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2011 and Note 16 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 .

In connection with the Southern Union Merger, purported stockholders of Southern Union have filed several stockholder class action lawsuits against us, Southern Union, and the Southern Union Board in the District Courts of Harris County, Texas and the Delaware Courts of Chancery. The Delaware lawsuits have been dismissed, while the Texas suits remain ongoing. Among other remedies, the plaintiffs seek monetary damages. It is our position that these lawsuits are without merit and we intend to contest them vigorously. If a final settlement is not reached in the Texas litigation, or if a dismissal is not obtained, these lawsuits could result in substantial costs to us and Southern Union, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against us and/or Southern Union related to the Southern Union Merger. The defense or settlement of any lawsuit or claim that remains unresolved may adversely affect the combined company's business, financial condition or results of operations.

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ITEM 1A. RISK FACTORS

ETP's recently completed Sunoco Merger presents several risks to our operating performance going forward. Some risks are similar to the risks associated with our existing business that have recently been disclosed. However, certain of those risks represent new risks related to our business or existing risks that have become more significant. The following risk factors should be read in conjunction with our risk factors described in "Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 and "Part II — Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

Risks Relating to Sunoco and Sunoco Logistics

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

As a result of Sunoco's planned exit from the refining business, Sunoco is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco's Philadelphia refinery. Sunoco may also need to contract for new ships, barges, pipelines or terminals which Sunoco has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at prices no less favorable than the market-based transfer price between Sunoco's refining and supply and retail marketing business segments or the failure of Sunoco's suppliers to deliver product in accordance with Sunoco's supply agreements may have a material adverse impact on Sunoco's business or results of operations.

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

Sunoco uses swaps, options, futures, forwards and other derivative instruments to hedge a variety of commodity price risks and to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in what Sunoco considers to be acceptable margins for various refined products and to lock in the price of a portion of Sunoco's electricity and natural gas purchases or sales and transportation costs. Sunoco does not hold or issue derivative instruments for speculative purposes. The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as Sunoco, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and required the Commodities Futures Trading Commission, or CFTC, and the United States Securities and Exchange Commission, or SEC, to promulgate rules and regulations implementing the new legislation. The CFTC also has proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require Sunoco to comply with margin requirements in connection with its derivative activities, although the application of those provisions to Sunoco is uncertain at this time. The financial reform legislation also requires many counterparties to Sunoco's derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including requirements to post collateral, which could adversely affect Sunoco's available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks Sunoco encounters, reduce Sunoco's ability to monetize or restructure its existing derivative contracts, and increase its exposure to less creditworthy counterparties. If Sunoco reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Sunoco's revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on Sunoco, its financial condition, and its results of operations.

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Sunoco depends upon Sunoco Logistics for a substantial portion of the logistics network that serves its refineries.

We indirectly own a 2% general partner interest in Sunoco Logistics, as well as all of the incentive distribution rights and a 32.4% limited partner interest in Sunoco Logistics. Sunoco Logistics owns and operates refined product and crude oil pipelines and terminals and conducts crude oil and refined product acquisition and marketing activities. Sunoco Logistics generates revenues by charging tariffs for transporting petroleum products and crude oil through its pipelines, by charging fees for terminalling and storing refined products and crude oil and by purchasing and selling crude oil and refined products. Sunoco Logistics serves Sunoco's refineries under long-term pipelines and terminals, storage and throughput agreements.

The business of Sunoco Logistics is subject to a variety of operating and regulatory risks.

Sunoco Logistics is subject to its own operating and regulatory risks, including, but not limited to:

• its reliance on its significant customers, including Sunoco;

• competition from other pipelines;

• environmental regulations affecting pipeline operations;

• operational hazards and risks;

• pipeline tariff regulations affecting the rates it can charge;

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

• other financial, operational and legal risks.

The occurrence of any of these risks could directly or indirectly affect Sunoco Logistics', as well as our results of operations and cash flows.

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

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

Similarly, a decrease in market demand for refined products could also impact throughput at Sunoco Logistics' pipelines and terminals. Material factors that could lead to a sustained decrease in market demand for refined products include a sustained recession or other adverse economic condition that results in lower purchases of refined petroleum products, higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions or other factors, higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products or a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy.

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

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

Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory. This statute also permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

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

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

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

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

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

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

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

Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on Sunoco's activities.

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Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require additional capital expenditures or expenses by Sunoco. Sunoco may have to enter into arrangements with other parties to meet its obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If Sunoco is unable to obtain or maintain sufficient quantities of ethanol to support its blending needs, its sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. Sunoco may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that Sunoco supplies. This potential increase in supply of gasoline and diesel could result in lower refining margins for us, particularly in the event of a contemporaneous reduction in demand, or during periods of sustained low demand for such refined products. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that Sunoco markets and sells.

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

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

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

•

Greenhouse gas emissions: Through the operation of Sunoco's refineries and marketing facilities, Sunoco's operations emit greenhouse gases, or GHG, including carbon dioxide. There are various legislative and regulatory measures to address monitoring, reporting or restriction of GHG emissions that are in various stages of review, discussion or implementation. These include federal and state actions to develop programs for the reduction of GHG emissions as well as proposals that would create a cap and trade system that would require Sunoco to purchase carbon emission allowances for emissions at Sunoco's manufacturing facilities and emissions caused by the use of the fuels that Sunoco sells. In response to findings that emissions of GHGs present an endangerment to public health and the environment, the United States Environmental Protection Agency, or EPA, has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered Prevention of Significant Deterioration, or PSD, and Title V permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is anticipated that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. These EPA rulemakings could adversely affect Sunoco's operations and restrict or delay Sunoco's ability to obtain air permits for new or modified facilities. In addition, the EPA published a final rule in October 2009 requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis beginning in 2011 for emissions occurring after January 1, 2010. Moreover, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as petroleum refineries, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from Sunoco's equipment and operations could require Sunoco to incur costs to reduce emissions of GHGs

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associated with Sunoco's operations or could adversely affect demand for the refined petroleum products that Sunoco produces and markets.

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

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

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

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

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

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

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

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against Sunoco would not have a material adverse effect on Sunoco's business or results of operations.

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

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

From time to time, new legislation or regulations are adopted by the federal government and various states or other regulatory bodies. Any such federal or state legislation or regulations, including but not limited to any potential environmental rules and regulations, tax legislation, energy policy legislation or legislation affecting trade or commercial practices, could have a significant impact on market conditions and could adversely affect Sunoco's business or results of operations in a material way.

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

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

Sunoco Logistics faces strong competition.

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

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

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

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

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

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

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


•	incurrence of additional indebtedness;


•	issuance of preferred stock by Sunoco's subsidiaries;


•	incurrence of liens;


•	sale and leaseback transactions;


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


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

Sunoco Logistics has credit facilities which also contain certain covenants. Increased borrowings by Sunoco Logistics will raise the level of Sunoco's total consolidated net indebtedness, and could restrict Sunoco's ability to borrow money or otherwise incur additional debt. If Sunoco does not comply with the covenants and other terms and provisions of its credit facilities, Sunoco will be required to request a waiver under, or an amendment to, those facilities. If Sunoco cannot obtain such a waiver or amendment, or if Sunoco fails to comply with the covenants and other terms and provisions of Sunoco's indentures, Sunoco would be in default

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under its debt instruments. Any defaults may cause the indebtedness under the facilities to become immediately due and payable, which could have a material adverse effect on Sunoco's financial position.

Sunoco's ability to meet its debt service obligations depends upon its future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting its operations, many of which are beyond Sunoco's control. A portion of Sunoco's cash flow from operations is needed to pay the principal of, and interest on, Sunoco's indebtedness and is not available for other purposes. If Sunoco is unable to generate sufficient cash flow from operations, Sunoco may have to sell assets, refinance all or a portion of its indebtedness or obtain additional financing. Any of these actions could have a material adverse effect on Sunoco's financial position.

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

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

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

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

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

Sunoco has substantial benefit obligations in connection with its noncontributory defined benefit pension plans. Sunoco has made contributions to the plans over the past several years to improve their funded status, and Sunoco expects to make additional contributions to the plans in the future as well. The projected benefit obligation of Sunoco's funded defined benefit plans at December 31, 2011 exceeded the market value of Sunoco's plan assets by $160 million. Sunoco expects that upon its exit from the refining business, defined benefit pension plans will be frozen for all participants and no additional benefits will be earned. As a result of the workforce reduction, divestments and the shutdown of Sunoco's Eagle Point refinery, Sunoco incurred noncash settlement and curtailment losses and special termination benefits in these plans during 2011, 2010 and 2009 totaling approximately $60, $55 and $130 million pretax, respectively. Sunoco expects to incur additional settlement losses related to the exit from the refining business. In 2010, Sunoco contributed $234 million to its funded defined benefit plans consisting of $144 million of cash and 3.59 million shares of Sunoco common stock valued at $90 million. Poor performance of the financial markets, or decreases in interest rates, could result in additional significant charges to shareholders' equity and additional significant increases in future pension expense and funding requirements. To the extent that Sunoco has to fund its pension obligations with cash from operations, Sunoco may be at a disadvantage to some of its competitors who do not have the same level of obligations that Sunoco has.

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

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

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

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

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

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

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

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

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

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

In the ordinary course of Sunoco Logistics' business, Sunoco Logistics collects and stores sensitive data, including intellectual property, its proprietary business information and that of its customers, suppliers and business partners, and personally identifiable information of its employees, in Sunoco Logistics' data centers and on its networks. The secure processing, maintenance and transmission of this information is critical to Sunoco Logistics' operations and business strategy. Despite Sunoco Logistics' security

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measures, its information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise Sunoco Logistics' networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of Sunoco Logistics' operations, damage to its reputation, and loss of confidence in its products and services, which could adversely affect its business.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

(a) Exhibits

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.



	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.1			Amendment No. 1 to Amended and Restated Credit Agreement dated as of September 13, 2012, between Energy Transfer Equity, L.P., several banks and other financial institutions signatories, and Credit Suisse AG, as Administrative Agent for the Lenders
10.2	1-32740 (8-K)(8/8/12)	10.1	Amendment No.1 to Senior Secured Term Loan Agreement by and among Energy Transfer Equity, L.P. (the “Borrower”), the Restricted Persons party thereto, the Lenders party thereto and Credit Suisse AG, in its capacity as administrative agent for the Lenders dated as of August 2, 2012.
31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certification of President and 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			Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011; (ii) our Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011; (iii) our Consolidated Statements of Comprehensive Income for the nine months ended September 30, 2012 and 2011; (iv) our Consolidated Statement of Equity for the nine months ended September 30, 2012; (v) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011; and (vi) the notes to our Consolidated Financial Statements.

* Incorporated herein by reference.

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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 8, 2012	By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)

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Part I Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

ET 10-Q Quarter ended Sept. 30, 2012