10-Q

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

or

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

Commission File No. 1-6407

____________________________

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	75-0571592 (I.R.S. Employer Identification No.)
5051 Westheimer Road Houston, Texas 77056-5622 (Address of principal executive offices) (Zip code)

(713) 989-2000

(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 xNo ¨

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 xNo ¨

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 x    Accelerated filer ¨    Non-accelerated filer ¨    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 x

Southern Union Company meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.  Item 2 of Part I has been reduced and Item 3 of Part I and Items 2 and 3 of Part II have been omitted in accordance with Instruction H.

FORM 10-Q

September 30, 2012

SOUTHERN UNION COMPANY AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
PART I.  FINANCIAL INFORMATION
ITEM 1.  Financial Statements (Unaudited)	1
Condensed Consolidated Balance Sheet	2
Condensed Consolidated Statement of Operations	4
Condensed Consolidated Statements of Comprehensive Income (Loss)	5
Condensed Consolidated Statement of Stockholders' Equity	6
Condensed Consolidated Statements of Cash Flows	7
Notes to Consolidated Financial Statements	8
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	41
ITEM 4. Controls and Procedures	41
PART II. OTHER INFORMATION	42
ITEM 1. Legal Proceedings	42
ITEM 1A. Risk Factors	42
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
ITEM 3. Defaults Upon Senior Securities	42
ITEM 4. Mine Safety Disclosures	42
ITEM 5. Other Information	42
ITEM 6. Exhibits	43
SIGNATURE	44

i

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Southern Union Company and its subsidiaries (“Southern Union” or the “Company”) in periodic press releases and some oral statements of Southern Union officials during presentations about the Company, 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 Company believes 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 Company’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see "Part I - Item 1A. Risk Factors” in the Company's Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 24, 2012.

Definitions

The abbreviations, acronyms and industry terminology used in these financial statements on Form 10-Q are defined as follows:

Btu    British thermal units

CEO    Chief Executive Officer

CFO    Chief Financial Officer

Citrus    Citrus Corp.

Company    Southern Union and its subsidiaries

EITR    Effective income tax rate

EPA    United States Environmental Protection Agency

ETE    Energy Transfer Equity, L.P.

ETP    Energy Transfer Partners, L.P., a subsidiary of ETE

Exchange Act    Securities Exchange Act of 1934

FERC    Federal Energy Regulatory Commission    

Florida Gas    Florida Gas Transmission Company, LLC

GAAP    Accounting principles generally accepted in the United States of America

Gallons/d    gallons per day

Holdco    ETP Holdco Corporation

LIBOR    London Interbank Offer Rate

LNG    Liquefied natural gas

LNG Holdings    Trunkline LNG Holdings, LLC

MADEP    Massachusetts Department of Environmental Protection

MDPU    Massachusetts Department of Public Utilities

MGPs    Manufactured gas plants

MMBtu    Million British thermal units

MMBtu/d    Million British thermal units per day

MMcf    Million cubic feet

MMcf/d    Million cubic feet per day

MPSC    Missouri Public Service Commission

NGL    Natural gas liquids

NMED    New Mexico Environment Department

OPEB plans    Other postretirement employee benefit plans

Panhandle    Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs    Polychlorinated biphenyls

PEPL    Panhandle Eastern Pipe Line Company, LP

PEPL Holdings    PEPL Holdings, LLC

ppb    parts per billion

PRPs    Potentially responsible parties

RCRA    Resource Conservation and Recovery Act

Sea Robin    Sea Robin Pipeline Company, LLC

SEC    United States Securities and Exchange Commission

ii

Sigma    Sigma Acquisition Corporation

Southern Union    Southern Union Company    

SUGS    Southern Union Gas Services

Sunoco    Sunoco, Inc.

TBtu    Trillion British thermal units

TCEQ    Texas Commission on Environmental Quality

Trunkline    Trunkline Gas Company, LLC

Trunkline LNG    Trunkline LNG Company, LLC

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 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 includes amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company's proportionate ownership.

iii

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 to our condensed consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

1

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

	Successor			Predecessor
	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,027		$	23,640
Accounts receivable net of allowances of $1,352 and $2,325, respectively	160,697			270,741
Accounts receivable — affiliates	14,004			10,467
Inventories	192,117			204,235
Deferred natural gas purchases	47,596			50,716
Natural gas imbalances — receivable	25,520			54,549
Prepayments and other assets	34,263			42,675
Total current assets	481,224			657,023
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	6,908,730			7,195,747
Construction work in progress	181,301			103,862
	7,090,031			7,299,609
Accumulated depreciation and amortization	(124,877		)	(1,573,273		)
Net property, plant and equipment	6,965,154			5,726,336
DEFERRED CHARGES:
Regulatory assets	129,512			57,447
Other deferred charges	80,122			60,407
Total deferred charges	209,634			117,854
UNCONSOLIDATED INVESTMENTS	122,932			1,633,289
GOODWILL	2,030,271			89,227
OTHER NON-CURRENT ASSETS	70,597			47,130
Total assets	$	9,879,812		$	8,270,859

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

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars and units in thousands, except par value)

(unaudited)

	Successor			Predecessor
	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long–term debt	$	261,351		$	343,254
Notes payable	—			200,000
Notes payable — related party	166,217			—
Accounts payable and accrued liabilities	109,364			193,949
Accounts payable and accrued liabilities — related parties	32,251			178
Federal, state and local taxes payable	49,879			37,127
Accrued interest	41,568			33,837
Natural gas imbalances — payable	98,677			145,212
Derivative instruments	25,267			58,598
Other	109,732			112,135
Total current liabilities	894,306			1,124,290
LONG-TERM DEBT, less current portion	3,093,825			3,160,372
DEFERRED CREDITS	349,845			301,709
DEFERRED INCOME TAXES	1,707,225			1,044,877
COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDER'S EQUITY:
Common stock, $0.01 and $1 par value; 1 and 200,000 shares authorized; 1 and 126,142 shares issued, respectively	—			126,142
Premium on capital stock	3,913,143			1,934,102
Less: Treasury stock, nil and 1,298 shares, respectively, at cost	—			(33,228		)
Less: Common stock held in trust, 1 and 581 shares, respectively	—			(10,888		)
Deferred compensation plans	—			10,888
Accumulated other comprehensive loss	(3,736		)	(119,192		)
Retained earnings (accumulated deficit)	(74,796		)	731,787
Total stockholders' equity	3,834,611			2,639,611
Total liabilities and stockholders' equity	$	9,879,812		$	8,270,859

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands)

(unaudited)

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
OPERATING REVENUES	$	477,896		$	617,211
OPERATING EXPENSES:
Cost of natural gas and other energy	180,733			304,535
Operating, maintenance and general	121,325			125,710
Depreciation and amortization	75,710			59,327
Revenue–related taxes	3,835			4,268
Taxes, other than on income and revenues	14,575			12,845
Total operating expenses	396,178			506,685
OPERATING INCOME	81,718			110,526
OTHER INCOME (EXPENSE):
Interest expense	(34,639		)	(54,925		)
Earnings (losses) from unconsolidated investments	(1,065		)	26,686
Other, net	(69		)	191
Total other expenses, net	(35,773		)	(28,048		)
INCOME BEFORE INCOME TAX EXPENSE	45,945			82,478
Income tax expense	28,959			24,446
NET INCOME	$	16,986		$	58,032

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
OPERATING REVENUES	$	990,078		$	633,649		$	1,995,640
OPERATING EXPENSES:
Cost of natural gas and other energy	374,220			311,270			1,045,742
Operating, maintenance and general	306,606			134,921			370,562
Depreciation and amortization	154,909			56,544			177,949
Revenue–related taxes	8,370			9,867			26,835
Taxes, other than on income and revenues	31,304			14,296			40,972
Total operating expenses	875,409			526,898			1,662,060
OPERATING INCOME	114,669			106,751			333,580
OTHER INCOME (EXPENSE):
Interest expense	(96,323		)	(50,407		)	(165,429		)
Earnings (losses) from unconsolidated investments	(381		)	16,160			78,435
Other, net	122			284			557
Total other expenses, net	(96,582		)	(33,963		)	(86,437		)
INCOME BEFORE INCOME TAX EXPENSE	18,087			72,788			247,143
Income tax expense	27,883			22,871			68,676
NET INCOME (LOSS)	$	(9,796	)	$	49,917		$	178,467

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Net income	$	16,986		$	58,032
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	—			(31,586		)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,421
Change in fair value of commodity hedges	(3,534		)	5,395
Reclassification of unrealized gain on commodity hedges into earnings	(3,845		)	(3,581		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			709
Change in other comprehensive income from equity investments	(291		)	35
	(7,670		)	(25,607		)
Comprehensive income	$	9,316		$	32,425

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Net income (loss)	$	(9,796	)	$	49,917		$	178,467
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	—			3,878			(44,577		)
Reclassification of unrealized loss on interest rate hedges into earnings	—			4,946			10,106
Change in fair value of commodity hedges	3,743			2,954			4,746
Reclassification of unrealized gain on commodity hedges into earnings	(7,386		)	(1,307		)	(9,455		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			1,815			2,116
Change in other comprehensive income from equity investments	(93		)	29			107
	(3,736		)	12,315			(36,957		)
Comprehensive income (loss)	$	(13,532	)	$	62,232		$	141,510

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(Dollars in thousands)

(unaudited)

	Common Stock		Premium on Capital Stock			Treasury Stock, at cost			Common Stock Held In Trust			Deferred Compen- sation Plans			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Accumu-lated Deficit)			Total Stock- holders' Equity
Predecessor
Balance December 31, 2011	$	126,142	$	1,934,102		$	(33,228	)	$	(10,888	)	$	10,888		$	(119,192	)	$	731,787		$	2,639,611
Other comprehensive income, net of tax	—		—			—			—			—			12,315			—			12,315
Share–based compensation	—		1,654			—			—			—			—			—			1,654
Restricted stock issuances	186		(186		)	(2,864		)	—			—			—			—			(2,864		)
Exercise of stock options	5		79			—			—			—			—			—			84
Contributions to Trust	—		—			—			(399		)	399			—			—			—
Disbursements from Trust	—		—			—			650			(650		)	—			—			—
Purchase of treasury stock	—		—			(1,450,000		)	—			—			—			—			(1,450,000		)
Net income	—		—			—			—			—			—			49,917			49,917
Balance March 25, 2012	$	126,333	$	1,935,649		$	(1,486,092	)	$	(10,637	)	$	10,637		$	(106,877	)	$	781,704		$	1,250,717
Successor
Balance March 26, 2012	$	—	$	3,912,867		$	—		$	—		$	—		$	—		$	—		$	3,912,867
Other comprehensive loss, net of tax	—		—			—			—			—			(3,736		)	—			(3,736		)
Non-cash compensation expense	—		276			—			—			—			—			—			276
Dividends paid on common stock	—		—			—			—			—			—			(65,000		)	(65,000		)
Net loss	—		—			—			—			—			—			(9,796		)	(9,796		)
Balance September 30, 2012	$	—	$	3,913,143		$	—		$	—		$	—		$	(3,736	)	$	(74,796	)	$	3,834,611

The Company’s common stock was $1 par value in the predecessor period.  Therefore, the change in Common Stock, $1 par value, was equivalent to the change in the number of shares of common stock issued.

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

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(9,796	)	$	49,917		$	178,467
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization	154,909			56,544			177,949
Deferred income taxes	25,548			22,866			76,877
Provision for bad debts	5,678			1,013			12,433
Amortization of costs charged to interest	(16,642		)	1,165			4,342
Net gain on curtailment of OPEB plans	(15,332		)	—			—
Unrealized loss on derivatives	15,415			—			9,283
Share–based compensation expense	276			1,654			7,580
Earnings from unconsolidated investments, net of cash distributions	4,749			(16,160		)	(75,105		)
Changes in operating assets and liabilities, net of Merger impact	(187,450		)	79,919			59,068
Net cash flows provided by (used in) operating activities	(22,645		)	196,918			450,894
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	(138,229		)	(60,062		)	(226,178		)
Loan to unconsolidated investments	—			—			(72,000		)
Loan repayments from unconsolidated investments	—			37,000			35,000
Proceeds from Citrus Merger	—			1,895,000			—
Plant retirements and other	(2,875		)	(2,252		)	(1,892		)
Net cash flows provided by (used in) investing activities	(141,104		)	1,869,686			(265,070		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			455,000			—
Renewal cost for credit facilities and issuance cost of debt	(1,708		)	(1,803		)	(2,162		)
Dividends paid on common stock	(65,000		)	(18,726		)	(56,099		)
Note payable — related party	221,217			—			—
Repayment of note payable — related party	(55,000		)	—			—
Repayment of long-term debt	(297		)	(1,047,529		)	(421		)
Net change in revolving credit facilities	38,614			12,386			(131,648		)
Purchase of treasury stock	—			(1,450,000		)	—
Other	(3,842		)	(2,780		)	3,321
Net cash flows provided by (used in) financing activities	133,984			(2,053,452		)	(187,009		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(29,765		)	13,152			(1,185		)
CASH AND CASH EQUIVALENTS, beginning of period	36,792			23,640			3,299
CASH AND CASH EQUIVALENTS, end of period	$	7,027		$	36,792		$	2,114

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

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in thousands)

(unaudited)

The accompanying unaudited interim condensed consolidated financial statements of the Companyhave been prepared pursuant to the rules and regulations of the SEC for quarterly reports on Form 10-Q.  These statements do not include all of the information and annual note disclosures required by GAAP, and should be read in conjunction with the Company’s financial statements and notes thereto for the year ended December 31, 2011, which are included in the Company’s Form 10-K filed with the SEC.  The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with GAAP and reflect adjustments that are, in the opinion of management, necessary for a fair statement of results for the interim period.  The year-end condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Due to the seasonal nature of the Company’s operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year.

1. DESCRIPTION OF BUSINESS:

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments as follows:  

• Transportation and Storage — 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 region.

• Gathering and Processing — 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.  

• Distribution — The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

See Note 3 for information related to the Company’s merger with ETE and the completion of the Holdco Transaction.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

There have been no changes in the Company’s accounting policies as disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011, except as noted below, as a result of the Company's merger with ETE.

Business Combination Accounting

The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 to our condensed consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

8

3. ETE MERGER AND HOLDCO TRANSACTION:

Description of Merger

On March 26, 2012, the Company, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among the Company, ETE and Merger Sub, Merger Sub was merged with and into the Company, with the Company continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).

At the Effective Time, each share of the Company’s common stock, par value $1.00 per share issued and outstanding (Southern Union Common Stock), immediately prior to the Effective Time (other than shares of Southern Union Common Stock held by stockholders properly exercising appraisal rights available under Section 262 of the Delaware General Corporation Law (DGCL) or shares of Southern Union Common Stock held directly or indirectly by the Company or any of its wholly-owned subsidiaries immediately prior to the Effective Time) was converted into the right to receive, as consideration for the Merger (the Merger Consideration), at the election of the holder of such share, either (i) $44.25 in cash (the Cash Consideration) or (ii) 1.00x ETE common unit (the Equity Consideration).

Under the terms of the Merger Agreement, Southern Union stockholders made an election to exchange each outstanding share of Southern Union Common Stock for $44.25 of cash or 1.00x ETE common unit, with no more than 60% of the aggregate

Merger Consideration payable in cash and no more than 50% of the aggregate Merger Consideration payable in ETE common units.  Based on the final election results, the Merger Consideration was paid as follows:

• Holders of approximately 54% of outstanding Southern Union Common Stock, or 67,985,929 Southern Union shares, elected and received cash.

• Holders of approximately 46% of outstanding Southern Union Common Stock, or 56,981,860 Southern Union shares, received ETE common units.  This amount is comprised of 38,872,598 Southern Union shares for which holders elected to receive ETE common units and 18,109,262 Southern Union shares for which holders either did not make an election (other than dissenting shares), did not deliver a valid election form prior to the election deadline or did not properly deliver shares of Southern Union Common Stock for which elections were made pursuant to the notice of guaranteed delivery procedure and, therefore, were deemed to have elected to receive ETE common units.

In connection with the consummation of the ETE Merger, on March 27, 2012, the New York Stock Exchange (NYSE) filed a notification of removal from listing with the SEC to delist the Southern Union Common Stock from the NYSE.  In addition, the Company filed with the SEC a certification and notice of termination requesting that the Southern Union Common Stock be deregistered under Section 12(b) of the Securities Exchange Act of 1934, as amended.

Pursuant to the Third Amended and Restated Company 2003 Stock and Incentive Plan (the Equity Plan), individual award agreements thereunder and the terms of the Merger Agreement, all awards of stock options and stock appreciation rights outstanding immediately, to the extent not already vested, became vested and exercisable prior to the Effective Time, in accordance with the terms of the Equity Plan.  All unexercised options and stock appreciation rights, including those for which vesting was accelerated, outstanding immediately prior to the Effective Time were cancelled and terminated at the Effective Time.  In consideration of such cancellation and termination, each stock option and stock appreciation right so cancelled and terminated was converted into the right to receive an amount in cash equal to $44.25 less (i) the applicable exercise price and (ii) any applicable deductions and withholdings required by law.

Additionally, shares of restricted stock for which restrictions have not otherwise lapsed or expired and were outstanding prior to the Effective Time had their associated restrictions automatically and without an action by the holder lapse/expire prior to the Effective Time, and each share of Southern Union Common Stock subject to such restricted stock grant was issued and converted into the right to receive Merger Consideration (in the form of Cash Consideration or Equity Consideration at the election of the holder of such restricted stock grant), less all deductions and withholdings required by law.  Each holder of the outstanding restricted stock grant made an election of Equity Consideration and the applicable deduction was made by reducing the number of ETE common units otherwise payable as part of the consideration for such restricted stock (with the ETE common units valued at the closing price of ETE on the day prior to the closing of the Merger for this purpose).

Restrictions on each awards of cash restricted stock units outstanding immediately prior to the Effective Time expired and each restricted stock unit was converted into the right to receive a lump sum cash payment equal to (i) $44.25 multiplied by

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the total number of shares of Southern Union Common Stock underlying such restricted stock units, less (ii) any applicable deductions and withholdings required by law.

The vesting of the equity-based awards, as described above, occurred as required under the change in control provisions of the Equity Plan.  The total remaining unrecognized compensation costs of $24.9 million associated with such vested awards was not recorded in either of the predecessor or successor periods reflected herein. The total of $136.8 million and 178,851 ETE Common Units issued to the holders of the awards in connection with the vesting was accounted for as consideration transferred in the Merger.

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, LLC, an indirect wholly-owned subsidiary of the Company (CrossCountry Energy), ETP, Citrus ETP Acquisition, L.L.C. (ETP Merger Sub), Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of the Company (PEPL Holdings), and the Company consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and the Company, on the other hand.

Immediately prior to the Effective Time, the Company, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder to, and the Company assumed the obligations and rights of ETE thereunder.  The Company made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus.  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) the Company contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, the Company entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which the Company agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to the Company) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

Expenses Related to the Merger

Merger-related expenses were $72.1 million and $18.7 million in the successor and predecessor periods in 2012, respectively.  Such expenses include legal and other outside service costs, charges resulting from employment agreements with certain executives that provided for compensation when their employment was terminated and severance costs associated with administrative headcount reductions. These expenses were included in Operating, maintenance, and general expenses in the unaudited condensed consolidated statement of operations.

Allocation of Consideration Transferred

The Merger was accounted for using business combination accounting under applicable accounting principles.  Business combination accounting 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. 

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The table below represents the allocation of the total consideration to Southern Union’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values.  Certain amounts included in the preliminary purchase price allocation as of September 30, 2012 have been changed from amounts previously reflected based on management's review of the valuation. Management is continuing to validate certain assumptions made in connection with the purchase price allocation.

Cash and cash equivalents	$	36,792
Other current assets	524,246
Property and equipment	6,958,768
Goodwill	2,030,271
Identified intangibles (1)	55,000
Other noncurrent assets	290,360
Long-term debt, including current portion	(3,333,706		)
Deferred income taxes	(1,698,352		)
Other liabilities	(950,513		)
Total purchase price	$	3,912,866

⁽¹⁾ Identified intangibles will be amortized over an estimated life of approximately 17.5 years and are included in deferred charges in the unaudited condensed consolidated balance sheet.

The goodwill resulting from the Merger was primarily due to expected commercial and operational synergies and is not deductible for tax purposes. Goodwill was allocated by reportable business segment as $1.17 billion to the Transportation and Storage segment; $598.3 million to the Gathering and Processing segment; $251.8 million to the Distribution segment; and $10.8 million to Corporate and Other.

Holdco Transaction

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP's acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity, in exchange for a 60% equity interest in the new entity, Holdco, and (ii) ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. This transaction did not result in a new basis of accounting for Southern Union.

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4. RELATED PARTY TRANSACTIONS:

The following table provides a summary of the related party balances included in our condensed consolidated balance sheets at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Investment in ETP	$	100,182	$	—
Accounts receivable — affiliates (1)	14,004		10,467
Note payable — ETE (2)	166,217		—
Accounts payable — affiliates (3)	32,251		178

⁽¹⁾  Primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates.

⁽²⁾  See Note 6 for more information regarding the note payable to ETE.

⁽³⁾  Primarily related to various administrative and operating costs paid by affiliates on behalf of the Company.

The following table provides a summary of the related party activity included in our condensed consolidated statements of operations. Prior period amounts were not included as they were immaterial.

	Successor
	Three months ended September 30, 2012			Period from Acquisition (March 26, 2012) to September 30, 2012
Operating revenues — ETE	$	10,180		$	19,076
Cost of natural gas and other energy	4,688			13,170
Operating, maintenance and general	20,235			23,537
Interest expense	3,487			3,351
Losses from unconsolidated investments	(1,065		)	(381		)

5. COMPREHENSIVE INCOME (LOSS):

The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	(18,697	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			2,294
Change in fair value of commodity hedges	(1,992		)	3,039
Reclassification of unrealized gain on commodity hedges into earnings	(2,166		)	(2,017		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			566
Change in other comprehensive income from equity investments	—			23
Total	$	(4,158	)	$	(14,792	)

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	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	2,296		$	(26,454	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,139			6,775
Change in fair value of commodity hedges	2,108			1,665			2,674
Reclassification of unrealized gain on commodity hedges into earnings	(4,161		)	(736		)	(5,327		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			902			1,708
Change in other comprehensive income from equity investments	—			18			66
Total	$	(2,053	)	$	7,284		$	(20,558	)

The table below presents the components in accumulated other comprehensive income (loss), net of tax, as of the dates indicated:

	Successor			Predecessor
	September 30, 2012			December 31, 2011
Interest rate hedges	$	—		$	(50,259	)
Commodity hedges	(3,643		)	(11		)
Benefit plans:
Net actuarial loss and prior service costs — pensions	—			(51,845		)
Net actuarial gain and prior service credit — OPEB	—			(14,542		)
Equity investments	(93		)	(2,535		)
Total accumulated other comprehensive income (loss), net of tax	$	(3,736	)	$	(119,192	)

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6. DEBT OBLIGATIONS:

The following table sets forth the debt obligations of Southern Union and Panhandle at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Southern Union Credit Facility	$	251,000	$	200,000
Southern Union:
7.60% Senior Notes due 2024	359,765		359,765
8.25% Senior Notes due 2029	300,000		300,000
7.24% to 9.44% First Mortgage Bonds due 2020 to 2027	19,500		19,500
7.20% Junior Subordinated Notes due 2066 (1)	600,000		600,000
Term Loan due 2013	—		250,000
Note Payable	7,306		7,746
Unamortized fair value adjustments	53,426		—
	1,339,997		1,537,011
Panhandle:
6.05% Senior Notes due 2013	250,000		250,000
6.20% Senior Notes due 2017	300,000		300,000
8.125% Senior Notes due 2019	150,000		150,000
7.00% Senior Notes due 2029	66,305		66,305
7.00% Senior Notes due 2018	400,000		400,000
Term Loan due 2012	—		797,386
Term Loan due 2015	455,000		—
Net premiums on long-term debt	—		2,924
Unamortized fair value adjustments	142,874		—
	1,764,179		1,966,615
Note Payable — ETE	166,217		—
Total debt	3,521,393		3,703,626
Less: Current portion of long term debt	261,351		343,254
Less: Short-term debt (2)	166,217		200,000
Total long-term debt	$	3,093,825	$	3,160,372

⁽¹⁾  Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly.  See Interest Rate Swaps below for more information regarding the interest rate on these notes.

⁽²⁾  The Southern Union Credit Facility was included in short-term debt as of December 31, 2011, but not as of September 30, 2012. See discussion in "Credit Facilities" below.

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company's consolidated debt obligations at September 30, 2012 and December 31, 2011 was $3.55 billion and $3.96 billion, respectively. As of September 30, 2012 and December 31, 2011, the aggregate carrying amount of the Company's consolidated debt obligations was $3.52 billion and $3.70 billion, respectively. The fair value of the Company's consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Credit Facilities.  In March 2012, the Company entered into the Eighth Amended and Restated Revolving Credit Agreement with certain banks in the amount of $700 million (Southern Union Credit Facility).  The Southern Union Credit Facility is an amendment, restatement and refinancing of the Company’s $550 million Seventh Amended and Restated Revolving Credit Agreement.  The Southern Union Credit Facility is scheduled to mature on May 20, 2016.  The Company entered into the Southern Union Credit Facility in order to (i) obtain consent to the transactions contemplated by the Merger Agreement, the Citrus Merger Agreement and the Support Agreement; (ii) to increase the amount of the facility from $550 million to $700 million; and (iii) to modify certain covenants.  Borrowings under the Southern Union Credit Facility are available for the

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Company’s working capital, other general corporate 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 upon the credit rating for the Company’s senior unsecured notes.  The annualized interest rate for the Southern Union Credit Facility was 1.83% at September 30, 2012.

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 or indirect 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.

The Company previously classified borrowings under the Southern Union Credit Facility as short-term debt as the individual borrowings are generally for periods of 15 to 180 days. As of September 30, 2012, such borrowings have been classified as non-current based on the Company's expectation that such borrowings will be refinanced upon maturity. Therefore, the Southern Union Credit Facility is classified in the table above and in the consolidated balance sheet as short-term debt as of December 31, 2011 and as long-term debt as of September 30, 2012.

Term Loans.  In March 2012, the Company retired the $250 million term loan due August 2013 and the $465 million term loan of its indirect wholly owned subsidiary, LNG Holdings, due June 2012 ($342.4 million of which was outstanding) utilizing a combination of the merger consideration received in connection with the Citrus Merger and borrowings under the Southern Union Credit Facility.

In February 2012, the Company 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.

Note Payable – ETE.  On March 26, 2012, the Company received $221.2 million from ETE to pay certain expenses in connection with the Merger, including (i) payments made to employees related to outstanding awards of stock options, stock appreciation rights and restricted stock units; and (ii) payments to certain executives under applicable employment or change in control agreements, which provided for compensation when their employment was terminated in connection with a change in control.  In connection with the receipt of the $221.2 million from ETE, on March 26, 2012, the Company entered into an interest-bearing promissory note payable on or before March 25, 2013.  The interest rate under the promissory note is 3.75% and accrued interest is payable monthly in arrears. A payment of $55.0 million to ETE was made in May 2012.

Panhandle 6.05% Senior Notes due 2013. Panhandle has $250 million of senior notes which mature within the next twelve months.  Panhandle currently expects to refinance all or a portion of the debt upon maturity or, alternatively, to retire all or a portion of the debt with proceeds from repayment of the note receivable from Southern Union.

Interest Rate Swaps.  The Company had interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on a portion of the $600 million Junior Subordinated Notes due 2066 (Junior Subordinated Notes).  See Note 9for more information regarding these swap agreements.

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7. BENEFITS:

Components of Net Periodic Benefit Cost

The following tables set forth the components of net periodic benefit cost (credit) of the Company’s pension and postretirement benefit plans for the periods presented below:

	Pension Benefits						Other Postretirement Benefits
	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Three months ended September 30, 2012			Three months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	1,132		$	935		$	188		$	880
Interest cost	2,269			2,526			614			1,446
Expected return on plan assets	(2,994		)	(2,646		)	(1,622		)	(1,450		)
Prior service cost (credit) amortization	—			146			—			(453		)
Actuarial loss (gain) amortization	—			1,984			—			(402		)
	407			2,945			(820		)	21
Regulatory adjustment (2)	2,919			192			726			667
Net periodic benefit cost (credit)	$	3,326		$	3,137		$	(94	)	$	688

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	2,358		$	998		$	2,805		$	411		$	881		$	2,641
Interest cost	4,728			2,095			7,576			1,276			1,254			4,338
Expected return on plan assets	(6,238		)	(2,461		)	(7,939		)	(3,380		)	(1,367		)	(4,349		)
Prior service cost (credit) amortization	—			133			440			—			(409		)	(1,359		)
Actuarial loss (gain) amortization	—			2,308			5,951			—			273			(1,208		)
Curtailment recognition (1)	—			—			—			(15,332		)	—			—
	848			3,073			8,833			(17,025		)	632			63
Regulatory adjustment (2)	5,892			253			575			1,464			657			1,999
Net periodic benefit cost (credit)	$	6,740		$	3,326		$	9,408		$	(15,561	)	$	1,289		$	2,062

⁽¹⁾  Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $74.6

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million.  Such gain was offset by establishment of a non-current refund liability in the amount of $59.3 million.  As such, the net curtailment gain recognition was $15.3 million.

⁽²⁾  In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

8. TAXES ON INCOME:

The following tables summarize the Company’s income taxes for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	(745	)
State	2,272			(143		)
Total	1,853			(888		)
Deferred expense:
Federal	25,742			21,903
State	1,364			3,431
Total	27,106			25,334
Total federal and state income tax expense	$	28,959		$	24,446
Effective tax rate	63		%	30		%

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	—		$	(572	)
State	2,754			5			(7,629		)
Total	2,335			5			(8,201		)
Deferred expense:
Federal	23,928			19,861			70,507
State	1,620			3,005			6,370
Total	25,548			22,866			76,877
Total federal and state income tax expense	$	27,883		$	22,871		$	68,676
Effective tax rate	154		%	31		%	28		%

In the predecessor period, the Company’s EITR was generally lower than the U.S. federal income tax statutory rate of 35% primarily due to the expected deductions for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated investment in Citrus.  In the successor period, the earnings from Citrus and the related dividends received deductions will no longer be applicable because of the Company’s contribution of its unconsolidated investment in Citrus to ETP, a subsidiary of ETE.  In the successor period, the Company’s EITR was impacted by non-deductible excess parachute payments resulting from Merger-related employee severance expenses.

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9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company is exposed to certain risks in its ongoing business operations.  The primary risks managed by using derivative instruments are interest rate risk and commodity price risk.  Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time.  Natural gas and NGL price swaps as well as call options and NGL processing spread swaps are the principal derivative instruments used by the Company 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.  

The Company recognizes all derivative instruments as assets or liabilities at fair value in the unaudited interim condensed consolidated balance sheets.

Interest Rate Contracts

The Company may enter into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and may enter into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.

Interest Rate Swaps.  In 2011, the Company entered into interest rate swap agreements to hedge the $600 million Junior Subordinated Notes with an aggregate notional amount of $525 million, of which $450 million were for ten-year periods and $75 million were for five-year periods.  These interest rate swaps became effective on November 1, 2011.  The Company pays interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011.  The interest rate swaps effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notes and are accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  The floating rate LIBOR-based portion of the interest payments was exchanged for weighted average fixed rate interest payments of 3.63%.  In conjunction with the Merger, the Company discontinued hedge accounting treatment on these interest rate swaps.  Therefore, future changes in fair value will be recognized in earnings.

The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012.  These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified intointerest expense in the same periods during which the related interest payments on long-term debt impacted earnings.  These swaps terminated in the first quarter of 2012.

For the predecessor period in 2012 during which hedge accounting treatment was applied, there was no swap ineffectiveness.

Treasury Rate Locks.  As of September 30, 2012, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt.  During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

Commodity Contracts – Gathering and Processing Segment

The Company 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 natural gas and NGL volumes resulting from movements in market commodity prices.

Natural Gas Price Swaps.  As of September 30, 2012, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 2,760,000 MMBtu for the remainder of 2012 and 10,037,500 MMBtu for 2013.  These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of September 30, 2012, approximately $0.7 million of net after-tax losses in accumulated other comprehensive income related to these natural gas price swaps are expected to be recognized in operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Price Swaps.  As of September 30, 2012, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 16,449,048 gallons (2,319,300 MMBtu equivalent basis) for the remainder of 2012.  These NGL price

18

swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted NGL sales impact earnings.  As of September 30, 2012, approximately $6.1 million of net after-tax losses in accumulated other comprehensive income related to these NGL price swaps are expected to be recognized in operating revenues during the next 12 months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Commodity Contracts - Distribution Segment

The Company 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.

Natural Gas Price Swaps.  As of September 30, 2012, the Company had outstanding pay-fixed natural gas price swaps and call options with total notional amounts of 3,660,000 MMBtu, 12,130,000 MMBtu and 2,640,000 MMBtu for the remainder of 2012, 2013 and 2014, respectively.  These natural gas price swaps and call options are accounted for as economic hedges, with changes in their fair value recorded to deferred natural gas purchases.

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Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the unaudited interim condensed consolidated balance sheets at the dates indicated:

	Fair Value
	Asset Derivatives				Liability Derivatives
	Successor		Predecessor		Successor		Predecessor
Balance Sheet Location	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	—	$	19,936
Deferred credits	—		—		—		59,789
Commodity contracts — Gathering and Processing:
Natural gas price swaps
Prepayments and other assets	1,498		6,124		—		—
Accounts payable — related parties	—		—		7,135		—
NGL price swaps
Prepayments and other assets	4,323		—		—		1,996
Derivative instruments — liabilities	—		—		—		4,144
	$	5,821	$	6,124	$	7,135	$	85,865
Economic Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	17,310	$	—
Deferred credits	—		—		63,142		—
Commodity contracts — Gathering and Processing:
Other derivative instruments
Derivative instruments — liabilities	—		—		—		50
Commodity contracts — Distribution:
Natural gas price swaps
Other non-current assets	768		—		—		—
Derivative instruments — liabilities	—		—		7,958		34,468
Deferred credits	—		3		—		5,643
	$	768	$	3	$	88,410	$	40,161
Total	$	6,589	$	6,127	$	95,545	$	126,026

The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim condensed consolidated balance sheet on a net basis and disclosed herein on a gross basis.

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The following tables summarize the location and amount (excluding income tax effects) of derivative instrument gains and losses reported in the Company’s unaudited interim condensed consolidated financial statements for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	50,283
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			5,715
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in accumulated other comprehensive income	(5,526		)	8,434
Reclassification of unrealized gain from accumulated other comprehensive income - increase of operating revenues	6,011			5,598
Economic Hedges:
Interest rate contracts:
Change in fair value - increase ininterest expense	(4,294		)	—
Commodity contracts - Gathering and Processing:
Change in fair value of hedges - decrease in operating revenues	—			3,963
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in deferred natural gas purchases	(10,866		)	10,114

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	6,174		$	71,031
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			8,085			16,881
Commodity contracts - Gathering and Processing:
Change in fair value - increase in accumulated other comprehensive income	5,851			4,619			7,420
Reclassification of unrealized gain from accumulated other comprehensive income	11,547			2,043			14,782
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	15,415			—			—
Commodity contracts - Gathering and Processing:
Change in fair value of other hedges - decrease in operating revenues	—			50			27,611
Commodity contracts - Distribution:
Change in fair value - decrease in deferred natural gas purchases	(30,961		)	(1,957		)	(13,658		)

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Derivative Instrument Contingent Features

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

10. FAIR VALUE MEASUREMENT:

The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the date indicated:

	Fair Value Measurements at September 30, 2012
	Fair Value Total		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	6,589	$	—	$	6,589	$	—
Total	$	6,589	$	—	$	6,589	$	—
Liabilities:
Commodity derivatives	$	15,093	$	—	$	15,093	$	—
Interest-rate swap derivatives	80,452		—		80,452		—
Total	$	95,545	$	—	$	95,545	$	—

The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps.  The pricing models also adjust for nonperformance risk associated with the counterparty or the Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value at September 30, 2012 or December 31, 2011 and there were no transfers between levels.

The approximate fair values of the Company’s cash and cash equivalents, accounts receivable and accounts payable are equal to book value, due to their short-term nature.

11. COMMITMENTS AND CONTINGENCIES:

Environmental Matters

The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

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Environmental Remediation

Transportation and Storage Segment

Panhandle is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing PCBs in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has implemented a program to remediate such contamination.  The primary remaining remediation activity on the Panhandle systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location.  The PCB assessments are ongoing and the related estimated remediation costs are subject to further change.

Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility.  The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, Panhandle may share liability associated with contamination with other PRPs.  Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.

Gathering and Processing Segment

SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons.  SUGS has a program to remediate such contamination.  The remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations.

Distribution Segment

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment.  Significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas.” Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

North Attleboro MGP Site in Massachusetts (North Attleboro Site).  In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  Assessment activities have recently been completed and it is estimated that the Company will spend approximately

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$10.5 million over the next several years to complete remediation activities at the North Attleboro Site, as well as maintain the engineered barrier constructed in 2008 at the upland portion of the site.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in regulatory assets in the unaudited interim condensed consolidated balance sheets.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the condensed consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Current	$	4,363	$	9,353
Noncurrent	24,588		11,635
Total environmental liabilities	$	28,951	$	20,988

Litigation and Other Claims

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, the Company 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.  The Company 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 (AG) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with the Company’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling $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, the Company’s former Vice Chairman, President and COO, joined the Company’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 the Company’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  The Company has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of the Company’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by the Company 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.  The Company believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, the Company 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.

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Compliance Orders from the New Mexico Environmental Department

SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities.  The NMED has issued amended compliance orders (COs) 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 COs were delayed to allow the parties to pursue substantive settlement discussions.  SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations.  The Company has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

Litigation Relating to the Merger with ETE

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 333^rd Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The plaintiff alleged that the defendants breached their fiduciary duties to Southern Union’s stockholders or aided and abetted breaches of fiduciary duties in connection with the Merger.  The petition alleged that the Merger involves an unfair price and an inadequate sales process and that defendants entered into the transaction to benefit themselves personally.  The petition sought injunctive relief, including an injunction of the Merger, attorneys’ and other fees and costs, indemnification and other relief.

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 11^th Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, Southern Union, and ETE.  The plaintiff alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted those alleged breaches.  The petition alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The petition sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On June 28, 2011, and August 19, 2011, amended petitions were filed in the Magda and Jaroslawicz actions, respectively, naming the same defendants and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  The two Texas cases have been consolidated with the following style: In re:  Southern Union Company; Cause No. 2011-37091, in the 333^rd 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.  The 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 and further claimed that ETE aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors should deem a competing proposal made by The Williams Companies, Inc. (Williams) to be superior.  The complaint sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

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.  The complaints named as defendants the members of the Southern Union Board, Southern Union, ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that ETE aided and abetted those alleged breaches.  The complaints alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors must give full consideration to the Williams proposal.  The complaints sought

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compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

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.  The complaint named as defendants the members of the Southern Union Board, Southern Union ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the amended Merger agreement and that Southern Union, ETE and Merger Sub aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that the terms of the amended Merger agreement are preclusive.  The complaint sought injunctive relief, including an injunction of the 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, 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 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 seeks injunctive relief, including an injunction of the 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 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 of voluntary dismissal of all claims without prejudice with the Delaware Court of Chancery.  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, captioned In re Southern Union Company, and docketed at Cause No. 2011-37091.

The Company has not recorded an accrued liability, believes the allegations of all the foregoing actions related to the Merger with ETE 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 Energy Transfer Partners, GP, L.P. (ETP GP), Energy Transfer Partners, LLC (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 assets to AmeriGas Partners, L.P. (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

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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.

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 is not currently set.

Mercury Release

In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (District Court) alleging violation of permitting requirements under the federal RCRA and notification requirements under the Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. Trial commenced on September 22, 2008, and on October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On October 2, 2009, the District Court imposed a fine of $6 million and a payment of $12 million in community service.

On December 22, 2010, the United States Court of Appeals for the First Circuit (First Circuit) affirmed the conviction and the sentence. On February 17, 2011, the First Circuit denied the Company's petition for en banc rehearing.  The Company, on October 31, 2011, filed a petition for a writ of certiorari review by the United States Supreme Court (Supreme Court), which review was granted and the case was heard by the Supreme Court on March 19, 2012.

On June 21, 2012, the United States Supreme Court reversed the First Circuit, holding that the sentence imposed on the Company was unconstitutional, and remanded the case back to the District Court for further proceeding consistent with that holding.

On July 17, 2012, the Government moved for “clarification” of the First Circuit's December 22, 2010 decision urging the First Circuit to find that, in addition to resolving whether (i) the alternative fine statute increases the maximum fine that may be imposed on the Company from $50,000 to $500,000; (ii) the $12 million community service obligation is a fine or restitution; and (iii) a new jury should be empanelled to hear evidence regarding the number of days RCRA was violated.

On July 26, 2012, the First Circuit vacated the fine imposed by the District Court and remanded the matter to the District Court for resentencing consistent with the Supreme Court's opinion. In the same order, the First Circuit denied without prejudice the Government's motion for clarification, holding that the issues raised by the Government in its July 17, 2012 motion could be addressed by the parties on remand. Accordingly, the Government has petitioned the District Court for consideration of the same issues with the hearing scheduled for December 3, 2012. A ruling against the Company would likely result in a judgment of up to approximately $750,000.

Liabilities for Litigation and Other Claims

In addition to the matters discussed above, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable.  When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made.  As of September 30, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $9.3 million and $28.3 million, respectively.  Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

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Other Commitments and Contingencies

Regulation and Rates.  See Note 13 for potential contingent matters associated with the Company’s regulated operations.

Unclaimed Property Audits.  The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and examination for compliance with these requirements.  The Company is currently being examined by a third party auditor on behalf of nine states for compliance with unclaimed property laws.

Air Quality Control

Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  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.  The Company is reviewing the new standards to determine the impact on its operations.

Transportation and Storage Segment.  In August 2010, the EPA finalized a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for certain engines regardless of size at Area Sources (sources that emit less than 10 tons per year of any one Hazardous Air Pollutant (HAP) or 25 tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit 10 tons per year or more of any one HAP or 25 tons per year of all HAPs).  Compliance is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

Nitrogen oxides are the primary air pollutant from natural gas-fired engines.  Nitrogen oxide emissions may form ozone in the atmosphere.  In 2008, the EPA lowered the ozone standard to 75 ppbwith compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to 60 to 70 ppb in lieu of the 75 ppb standard, with compliance required in 2014 or later.  In September 2011, the EPA decided to rescind the proposed lower ozone standard and begin the process to implement the 75 ppb ozone standard established in 2008.

In January 2010, the EPA finalized a 100 ppb one-hour nitrogen dioxide standard.  The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013.  This new monitoring may result in additional nitrogen dioxide non-attainment areas.  In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

The Company is currently reviewing the potential impacts of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule, implementation of the 2008 ozone standard and the new nitrogen dioxide standard on operations in its Transportation and Storage and Gathering and Processing segments and the potential costs associated with the installation of emission control systems on its existing engines.  The ultimate costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes, based on the current understanding of the current and proposed rules, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursuing any emissions reductions from PEPL’s operations unless there are changes in the future regarding the status of the Kansas City area.

Gathering and Processing Segment.  The Texas Commission on Environmental Quality recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more.  If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air

28

Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard.  This may potentially affect three SUGS recovery units in Texas.  It is unclear at this time how the NMED will address the sulfur dioxide standard.

12. REPORTABLE SEGMENTS:

The Company’s primary operating segments, which are individually disclosed as its reportable business segments, are:  Transportation and Storage, Gathering and Processing, and Distribution.  These operating segments are organized for segment reporting purposes based on the way internal managerial reporting presents the results of the Company’s various businesses to its chief operating decision maker for use in determining the performance of the businesses.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus (through March 26, 2012, the date of the Citrus Merger).  The Gathering and Processing segment operations are conducted through SUGS.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts, through its Missouri Gas Energy and New England Gas Company operating divisions, respectively. See Note 1 for additional information associated with the Company’s reportable segments.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the nine months ended September 30, 2012 and 2011.

The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other activities.  Corporate and other activities consist of unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

The Company previously reported segment EBIT as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation. Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

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The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:

	Successor		Predecessor
	Three months ended September 30, 2012		Three months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	188,481	$	192,699
Gathering and Processing	213,382		339,658
Distribution	73,237		80,763
Total segment operating revenues	475,100		613,120
Corporate and other activities	2,796		4,091
	$	477,896	$	617,211

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012		Period from January 1, 2012 to March 25, 2012		Nine months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	387,173	$	193,921	$	584,753
Gathering and Processing	430,215		246,463		891,825
Distribution	167,742		190,499		506,412
Total segment operating revenues	985,130		630,883		1,982,990
Corporate and other activities	4,948		2,766		12,650
	$	990,078	$	633,649	$	1,995,640

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	122,486		$	199,952
Gathering and Processing	25,296			34,234
Distribution	22,461			14,369
Corporate and other activities	(1,065		)	(1,255		)
Total Segment Adjusted EBITDA	169,178			247,300
Depreciation and amortization	(75,710		)	(59,327		)
Unrealized gains on unhedged derivative activities	—			5,130
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(7,256		)	(2,926		)
Other, net	(755		)	191
Earnings (losses) from unconsolidated investments	(1,065		)	26,686
Adjusted EBITDA attributable to unconsolidated investments	(3,808		)	(79,651		)
Interest expense	(34,639		)	(54,925		)
Income before income tax expense	45,945			82,478
Income tax expense	(28,959		)	(24,446		)
Net income	$	16,986		$	58,032

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	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	205,130		$	185,706		$	570,072
Gathering and Processing	36,155			25,338			94,440
Distribution	35,907			33,554			58,673
Corporate and other activities	(2,471		)	(18,845		)	(70		)
Total Segment Adjusted EBITDA	274,721			225,753			723,115
Depreciation and amortization	(154,909		)	(56,544		)	(177,949		)
Unrealized losses on unhedged derivative activities	—			—			(9,283		)
Net gain on curtailment of OPEB plans	15,332			—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(12,116		)	(1,350		)	(7,580		)
Other, net	(564		)	284			557
Earnings (losses) from unconsolidated investments	(381		)	16,160			78,435
Adjusted EBITDA attributable to unconsolidated investments	(7,673		)	(61,108		)	(194,723		)
Interest expense	(96,323		)	(50,407		)	(165,429		)
Income before income tax expense	18,087			72,788			247,143
Income tax expense	(27,883		)	(22,871		)	(68,676		)
Net income (loss)	$	(9,796	)	$	49,917		$	178,467

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Total assets:
Transportation and Storage	$	5,695,305	$	5,288,967
Gathering and Processing	2,820,127		1,742,516
Distribution	1,249,047		1,075,253
Total segment assets	9,764,479		8,106,736
Corporate and other activities	115,333		164,123
Total assets	$	9,879,812	$	8,270,859

13. REGULATION AND RATES:

Panhandle.  In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline's offshore facilities, and certain related onshore facilities, by sale and transfer to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively.  Several parties filed interventions and protests of this filing.  On June 21, 2012, FERC issued an order granting Trunkline permission and approval to proceed with the transfer, subject to compliance with certain regulatory requirements.  On July 31, 2012 Sea Robin and Trunkline made the necessary compliance filings with FERC.  The transfer of the offshore facilities to Sea Robin was completed in the third quarter of this year.

On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate. This sale is subject to FERC approval. These facilities would be converted to a crude oil transportation service. Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission's requests for additional information on this application.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to 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.

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Missouri Gas Energy.  On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million.  On February 10, 2010, the MPSC issued its Report and Order in this case, authorizing a revenue increase of $16.2 million and approving distribution rate structures for Missouri Gas Energy’s residential and small general service customers (which comprised approximately 99% of its total customers and approximately 91% of its net operating revenues at the time the rates went into effect) that eliminate the impact of weather and conservation for residential and small general service margin revenues and related earnings in Missouri.  The new rates became effective February 28, 2010.  Judicial review of the MPSC’s Report and Order is being sought by the Office of the Public Counsel, with respect to rate structure issues, and by Missouri Gas Energy, with respect to cost of capital issues.  By opinion issued on March 20, 2012, the Southern District of the Missouri Court of Appeals affirmed the MPSC’s Report and Order.  That opinion is now final.

New England Gas Company.  On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50% of the amount by which its 2007 earnings fell below a return on equity of 7%.  This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007.  On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments (ESA) in its entirety.  The Company appealed that decision to the Massachusetts Supreme Judicial Court (MSJC).  On November 13, 2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $1.7 million, representing 50% of the amount by which its 2008 earnings deficiency fell below a return on equity of 7%.  The MDPU held the 2008 ESA matter in abeyance pending judicial resolution of the issues pertaining to the 2007 ESA.  On February 11, 2011, the MSJC issued an opinion reversing the MDPU’s rejection of New England Gas Company’s 2007 ESA and remanded the matter back to the MDPU to determine the appropriate amount of the 2007 ESA and the method for recovery.  On July 13, 2011, New England Gas Company filed its motion for proceeding on remand requesting that the MDPU (i) find that $4.1 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a twelve month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $1.7 million over a twelve-month period beginning November 1, 2012.  On January 27, 2012, the MDPU issued its order approving the 2007 ESA in its entirety and authorizing recovery of approximately $4 million over a twelve-month period beginning February 1, 2012.  The 2008 ESA is awaiting further action by the MDPU.

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands, except per gallon and per MMBtu amounts)

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying unaudited interim condensed consolidated financial statements and notes to help provide an understanding of the Company’s results of operations.  The following section includes an overview of the Company’s business as well as recent developments that management of the Company believes are important in understanding its results of operations and anticipating future trends in those operations.  Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and for each reportable segment.  The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction H to Form 10-Q.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is Segment Adjusted EBITDA.  For additional information related to the Company’s use of Segment Adjusted EBITDA as its primary financial measure for its reportable segments, see Note 12.

The Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  By the application of "push-down" accounting, the Company allocated the purchase price paid by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.  

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The most significant impacts of the new basis of accounting during the successor periods were (i) higher depreciation expense due to the step-up of depreciable assets and assignment of purchase price to certain amortizable intangible assets and (ii) lower interest expense (though not cash payments) for the remaining life of the related long-term debt due to its revaluation and related debt premium amortization. 

The results of operations for predecessor and successor periods included herein reflected certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the segments results below.

The Company previously reported segment EBIT as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation.

Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

The following table provides a reconciliation of Segment Adjusted EBITDA (by segment) to net earnings for the periods presented.

	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and storage segment	$	122,486		$	199,952		$	205,130		$	185,706		$	570,072
Gathering and processing segment	25,296			34,234			36,155			25,338			94,440
Distribution segment	22,461			14,369			35,907			33,554			58,673
Corporate and other activities	(1,065		)	(1,255		)	(2,471		)	(18,845		)	(70		)
Total Segment Adjusted EBITDA	169,178			247,300			274,721			225,753			723,115
Depreciation and amortization	(75,710		)	(59,327		)	(154,909		)	(56,544		)	(177,949		)
Unrealized gains (losses) on nonhedged derivative activities	—			5,130			—			—			(9,283		)
Interest expense	(34,639		)	(54,925		)	(96,323		)	(50,407		)	(165,429		)
Income tax expense	(28,959		)	(24,446		)	(27,883		)	(22,871		)	(68,676		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(7,256		)	(2,926		)	(12,116		)	(1,350		)	(7,580		)
Net gain on curtailment of OPEB plans	—			—			15,332			—			—
Other, net	(755		)	191			(564		)	284			557
Earnings (losses) from unconsolidated investments	(1,065		)	26,686			(381		)	16,160			78,435
Adjusted EBITDA attributable to unconsolidated investments	(3,808		)	(79,651		)	(7,673		)	(61,108		)	(194,723		)
Net income (loss)	$	16,986		$	58,032		$	(9,796	)	$	49,917		$	178,467

The segment analysis in the following section describes the significant items impacting the Segment Adjusted EBITDA amounts reflected above. In addition, as discussed in the “Overview” section above, the comparability of net income between predecessor and successor periods was impacted by the application of “push-down” accounting. The most significant impacts of this new basis of accounting were:

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• Incremental depreciation and amortization expense of approximately $13.2 million per quarter has been recognized in the successor periods subsequent to March 25, 2012 as a result of the application of the new basis of accounting.

• The application of “push-down” accounting also resulted in the Company's long-term debt being recorded at fair value, which impacted the amount of amortization recorded in interest expense. This change in the amount of amortization resulted in a net reduction within interest expense of approximately $9.6 million per quarter for period subsequent to March 25, 2012.

The Company's consolidated net income was also impacted by changes in income taxes that were driven by the ETE Merger; those impacts were described in the “Federal and State Income Taxes” section below.

The “Supplemental Pro Forma Information” section, which follows the “Business Segment Results” section, provides additional analysis of the Company's consolidated net income on a year-to-date basis, assuming the ETE Merger had been completed on January 1, 2011.

Federal and State Income Taxes

The following table sets forth the Company’s income taxes for the periods presented.

	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Income tax expense	$	28,959		$	24,446		$	27,883		$	22,871		$	68,676
Effective tax rate	63		%	30		%	154		%	31		%	28		%

The increases in the effective tax rate during the successor periods are primarily due to:

• The impact of non-deductible parachute payments resulting from the Merger-related employee severance expenses in the successor periods; and,

• Lower effective rates during the predecessor periods as a result of the dividend received deduction for the anticipated receipt of dividends associated with earnings from the Company's unconsolidated investment in Citrus. The dividend received deduction was not applicable to the successor periods as a result of the Company's contribution of its investment in Citrus to ETP concurrent with the ETE Merger on March 26, 2012.

Business Segment Results

Transportation and Storage Segment

The 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 Transportation and Storage segment’s operations, conducted through Panhandle and, through March 26, 2012 (the date of the Citrus Merger), Florida Gas, 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.  Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads.  See Note 3 for information related to the Citrus Merger.

The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers.  Shorter-term contracts, both firm and interruptible, tend to have a greater impact on the volatility of revenues.  Short-term and long-term contracts are affected by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices and basis differentials.  Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, which customers pay whether they utilize their contracted capacity or not, volumes transported do not have as significant an impact on revenues over the short-

34

term.  However, longer-term demand for capacity may be affected by changes in the customers’ actual and anticipated utilization of their contracted capacity and other factors.

The Company’s regulated transportation and storage businesses can file (or be required to file) for changes in their rates, which are subject to approval by FERC.  Although a significant portion of the Company’s contracts are discounted or negotiated rate contracts, changes in rates and other tariff provisions resulting from regulatory proceedings have the potential to impact negatively the Company’s results of operations and financial condition.

The following table illustrates the results of operations applicable to the Company’s Transportation and Storage segment for the periods presented.

	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Operating revenues (1)	$	188,481		$	192,699		$	387,173		$	193,921		$	584,753
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(60,181		)	(63,421		)	(170,015		)	(60,402		)	(181,614		)
Taxes other than on income and revenues	(9,189		)	(8,653		)	(18,979		)	(8,801		)	(26,392		)
Adjusted EBITDA attributable to unconsolidated investments	3,375			79,327			6,951			60,988			193,325
Segment Adjusted EBITDA	$	122,486		$	199,952		$	205,130		$	185,706		$	570,072
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	137			122			277			152			421
Trunkline	169			172			354			177			549
Sea Robin	24			24			47			20			92

⁽¹⁾  Reservation revenues comprised 88% and 89% of total operating revenues in the 2012 and 2011 three month periods, respectively. Reservation revenues comprised 88% of total operating revenues in the successor period from March 26, 2012 to September 30, 2012, and 88% and 89% of total operating revenues in the 2012 and 2011 predecessor periods, respectively.

⁽²⁾  Includes transportation deliveries made throughout the Company’s pipeline network.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company's Transportation and Storage segment.

• Unconsolidated Investments. The primary driver for the reduction in Segment Adjusted EBITDA for the Company's Transportation and Storage segment was the contribution of Citrus to ETP. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for all of the predecessor periods shown above but was not reflected in the successor periods. The predecessor periods reflected Adjusted EBITDA attributable to Citrus of $79.3 million and $193.3 million for the three and nine months ended September 30, 2011, respectively, and $60.9 million for the period from January 1, 2012 to March 25, 2012.

• Operating Revenues. On a daily average basis, operating revenues were slightly lower in the successor periods primarily due to the impact in the successor periods from lower summer capacity being sold.

• Operating, Maintenance and General Expenses. The period from March 26, 2012 to September 30, 2012 included $43.8 million of merger-related employee severance expenses. The nine months ended September 30, 2011 reflected legal expenses that were lower on a daily average basis than the legal expenses recorded during the predecessor and successor periods in 2012; this was due to settlement in 2011 of certain litigation with several contractors related to the Company's East End projects.

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Gathering and Processing Segment

The Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production (E&P) 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 NGL, and redelivering natural gas and NGL 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 E&P 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.

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Note 9.

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The following table presents the results of operations applicable to the Company’s Gathering and Processing segment for the period presented.

	Successor			Predecessor			Successor			Predecessor
	Three months ended September  30, 2012			Three months ended September  30, 2011			Period from Acquisition (March 26, 2012) to September  30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September  30, 2011
Operating revenues	$	213,382		$	339,658		$	430,215		$	246,463		$	891,825
Cost of natural gas and other energy (1)	(163,155		)	(276,816		)	(326,937		)	(195,840		)	(736,316		)
Gross margin (2)	50,227			62,842			103,278			50,623			155,509
Unrealized (gain) loss on commodity risk management activities	—			(5,130		)	—			—			9,283
Operating, maintenance and general, excluding non-cash compensation expense and accretion	(23,195		)	(22,825		)	(63,510		)	(23,446		)	(66,143		)
Taxes other than on income and revenues	(1,677		)	(680		)	(3,504		)	(1,787		)	(4,406		)
Adjusted EBITDA attributable to unconsolidated investments	(59		)	27			(109		)	(52		)	197
Segment Adjusted EBITDA	$	25,296		$	34,234		$	36,155		$	25,338		$	94,440
Operating Information:
Volumes:
Avg natural gas processed (MMBtu/d)	492,899			442,983			477,284			451,893			416,460
Avg NGL produced (gallons/d)	1,745,640			1,576,678			1,702,600			1,624,666			1,469,218
Avg natural gas wellhead volumes (MMBtu/d)	513,708			509,405			497,953			504,822			488,993
Natural gas sales (MMBtu)	21,357,984			19,381,028			45,212,064			16,017,102			54,016,320
NGL sales (gallons)	154,004,856			183,993,418			348,185,105			143,078,360			506,655,145
Average Pricing:
Realized natural gas ($/MMBtu)  (3)	$	2.75		$	4.01		$	2.49		$	2.44		$	4.08
Realized NGL ($/gallon)  (3)	0.92			1.38			0.94			1.17			1.32
Natural Gas Daily WAHA ($/MMBtu)	2.81			4.05			2.50			2.43			4.14
Natural Gas Daily El Paso ($/MMBtu)	2.78			4.01			2.47			2.42			4.09
Estimated plant processing spread ($/gallon)	0.60			0.99			0.68			0.96			0.94

⁽¹⁾  Cost of natural gas and other energy consists of natural gas and NGL purchase costs, fractionation and other fees.

⁽²⁾  Gross margin consists of operating revenues less cost of natural gas and other energy.  The Company believes that this measurement is meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods presented because commodity costs are a significant factor in the determination of the segment’s revenues.

⁽³⁾  Excludes impact of realized and unrealized commodity derivative gains and losses.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company's Gathering and Processing segment.

• Gross Margin. For the three months ended September 30, 2012 compared to the three months ended September 30, 2011, the decrease in Gathering and Processing Segment Adjusted EBITDA was primarily due to lower gross margin of $12.6

37

million resulting from lower market-driven realized natural gas and NGL prices. Realized average natural gas and NGL prices were $2.75 per MMBtu and $0.92 per gallon for the three months ended September 30, 2012 versus $4.01 per MMBtu and $1.38 per gallon for the three months ended September 30, 2011. With respect to year-to-date results, the predecessor and successor periods in 2012 also were lower (on a daily basis) compared to the year-to-date period in 2011 due to decreases in market-driven realized average natural gas and NGL prices. Realized average natural gas and NGL prices were $2.49 per MMBtu and $0.94 per gallon for the period from March 26, 2012 to September 30, 2012, $2.44 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012, and $4.08 per MMBtu and $1.32 per gallon for the nine months ended September 30, 2011.

• Operating, Maintenance and General Expenses. The period from March 26, 2012 to September 30, 2012 included $16.2 million of merger-related employee severance expenses. On a daily basis, operating, maintenance and general expenses have also increased between the end of the periods presented due to expansion of plant facilities.

Distribution Segment

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company operating divisions, respectively.  The Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates.  The Distribution 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.  For additional information related to rate matters within the Distribution segment, seeNote 13.

The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented.

	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Net operating revenues  (1)	$	52,694		$	49,993		$	114,442		$	65,675		$	173,465
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(26,779		)	(32,395		)	(70,981		)	(29,265		)	(105,637		)
Taxes other than on income and revenues	(3,454		)	(3,229		)	(7,554		)	(2,856		)	(9,155		)
Segment Adjusted EBITDA	$	22,461		$	14,369		$	35,907		$	33,554		$	58,673
Operating Information:
Natural gas sales volumes (MMcf)	3,047			3,182			10,300			19,957			43,002
Natural gas transported volumes (MMcf)	5,068			3,806			10,902			7,379			18,583
Weather – Degree Days: (2)
Missouri Gas Energy service territories	50			94			293			1,898			3,495
New England Gas Company service territories	68			49			806			2,170			3,634

38

⁽¹⁾  Operating revenues for the Distribution segment are reported net of cost of natural gas and other energy and revenue-related taxes, which are pass-through costs.

⁽²⁾  "Degree days" are a measure of the coldness of the weather experienced.  A degree day is equivalent to each degree that the daily mean temperature for a day falls below 65 degrees Fahrenheit.

Following is a discussion of the significant items and variance impacting Segment Adjusted EBITDA for the Company's Distribution segment.

• Net Operating Revenues. For the three months ended September 30, 2012 compared to the three months ended September 30, 2011, net operating revenues increased $2.7 million primarily due to a $9.8 million decrease in gas cost offset by a $7.5 million decrease in operating revenues. With respect to year-to-date results, the predecessor and successor periods in 2012 also were higher (on a daily basis) compared to the year-to-date period in 2011 due to new customer rates at New England Gas Company effective April 1, 2011.

• Operating, Maintenance and General Expenses. For the three months ended September 30, 2012 compared to the three months ended September 30, 2011, operating, maintenance and general expenses decreased primarily due to a non-cash rate case amortization adjustment. With respect to the year-to-date results, the predecessor and successor periods in 2012 also reflected lower uncollectible customer accounts as a result of lower gas costs and energy assistance payments.

Corporate and Other Activities

The period from January 1, 2012 to March 25, 2012 included $18.7 million of merger-related expenses.

See Note 3 for additional information related to the Company's merger with ETE.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of the Company has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the ETE Merger for the nine months ended September 30, 2012 and 2011, giving effect to the ETE Merger as if it had occurred on January 1, 2011. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the ETE Merger had been consummated on January 1, 2011.

39

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Pro forma adjustments				Pro forma nine months ended September 30, 2012
OPERATING REVENUES	$	990,078		$	633,649		$	—			$	1,623,727
OPERATING EXPENSES:
Cost of natural gas and other energy	374,220			311,270							685,490
Operating, maintenance and general	306,606			134,921			(75,561		)	(a)	365,966
Depreciation and amortization	154,909			56,544			12,362			(b)	223,815
Revenue–related taxes	8,370			9,867							18,237
Taxes, other than on income and revenues	31,304			14,296							45,600
Total operating expenses	875,409			526,898			(63,199		)		1,339,108
OPERATING INCOME	114,669			106,751			63,199				284,619
OTHER INCOME (EXPENSE):
Interest expense	(96,323		)	(50,407		)	8,906			(c)	(137,824		)
Earnings (losses) from unconsolidated investments	(381		)	16,160			(15,560		)	(d)	219
Other, net	122			284			—				406
Total other expenses, net	(96,582		)	(33,963		)	(6,654		)		(137,199		)
INCOME BEFORE INCOME TAX EXPENSE	18,087			72,788			56,545				147,420
Income tax expense	27,883			22,871			6,588			(e)	57,342
NET INCOME (LOSS)	$	(9,796	)	$	49,917		$	49,957			$	90,078

	Predecessor
	Nine months ended September 30, 2011			Pro forma adjustments				Pro forma nine months ended September 30, 2011
OPERATING REVENUES	$	1,995,640		$	—			$	1,995,640
OPERATING EXPENSES:
Cost of natural gas and other energy	1,045,742			—				1,045,742
Operating, maintenance and general	370,562			(8,610		)	(a)	361,952
Depreciation and amortization	177,949			39,703			(b)	217,652
Revenue–related taxes	26,835			—				26,835
Taxes, other than on income and revenues	40,972			—				40,972
Total operating expenses	1,662,060			31,093				1,693,153
OPERATING INCOME	333,580			(31,093		)		302,487
OTHER INCOME (EXPENSE):
Interest expense	(165,429		)	28,603			(c)	(136,826		)
Earnings (losses) from unconsolidated investments	78,435			(75,300		)	(d)	3,135
Other, net	557			—				557
Total other expenses, net	(86,437		)	(46,697		)		(133,134		)
INCOME BEFORE INCOME TAX EXPENSE	247,143			(77,790		)		169,353
Income tax expense	68,676			(6,012		)	(e)	62,664
NET INCOME (LOSS)	$	178,467		$	(71,778	)		$	106,689

40

(a) To eliminate the merger-related costs incurred by the Company in connection with the ETE Merger, including change in control and severance costs. These costs are eliminated from the Company's pro forma income statement because such costs would not have a continuing impact on the Company's results of operations.

(b) To record incremental depreciation on the excess purchase price allocated to property, plant and equipment based on a weighted average useful life of 24 years.

(c) To adjust amortization included in interest expense to (i) reverse historical amortization of financing costs and fair value adjustments related to debt and (ii) record pro forma amortization related to the pro forma adjustment of the Company's debt to fair value.

(d) To adjust earnings from unconsolidated investments to (i) eliminate historical earnings related to Citrus to give effect to the transfer of the Company's interest in Citrus in connection with the ETE Merger and (ii) record incremental earnings from the Company's investment in ETP common units received in connection with the transfer of Citrus.

(e) To reflect income tax impacts from the pro forma adjustments to pre-tax income, including the elimination of the dividend received deduction recorded in the historical income tax provision for the predecessor periods in connection with the Company's investment in Citrus.

Analysis of Supplemental Pro Forma Financial Information

Following is a discussion of the significant items impacting the pro forma results for the nine months ended September 30, 2012 compared to pro forma results for the nine months ended September 30, 2011.

• Pro forma operating revenues and cost of natural gas and other energy decreased between periods primarily due to the actual results from the Company's Gathering and Processing segment attributable to (i) lower throughput volumes in the 2012 period as a result of processing plant outages and producer well freeze-offs resulting from unusually cold weather in early 2011, (ii) the impact of lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $2.48 per MMBtu and $1.01 per gallon in the 2012 period versus $4.08 per MMBtu and $1.32 per gallon in the 2011 period, and (iii) the impact of an unrealized loss on commodity risk management activities of $9.3 million in the 2011 period.

• Pro forma interest expense increased between periods primarily due to an increase of $15.4 million resulting from the change in fair value of the interest rate swaps related to the Junior Subordinated Notes (for which hedge accounting treatment was discontinued in March 2012). This increase was partially offset by lower interest expense of $13.7 million related to the term loan repayment in February 2012.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 3, Quantitative and Qualitative Disclosures About Market Risk, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.  The Company performed an evaluation under the supervision and with the participation of management, including its principal executive officer and principal financial officer, and with the participation of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report.  Based on that evaluation, Southern Union’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2012.

41

Changes in Internal Control over Financial Reporting

Subsequent to the merger with ETE in March 2012, the Company’s internal controls over financial reporting, including certain disclosure controls and corporate governance procedures, have been impacted by changes made to conform to the existing controls of ETE.  Additional changes are expected to occur in future periods.  None of these changes are in response to any identified deficiency or weakness in the Company’s internal control over financial reporting.

There were no other changes in the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to affect, its internal controls over financial reporting.

PART II.  OTHER INFORMATION

ITEM 1.   Legal Proceedings.

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Note 11 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Note 14 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2011.

Southern Union is subject to federal and state requirements for the protection of the environment, including those for the discharge of hazardous materials and remediation of contaminated sites.  As a result, Southern Union is a party to or has its property subject to various other lawsuits or proceedings involving environmental protection matters.  For information regarding these matters, see Note 11 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Note 14 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2011.

ITEM 1A.  RISK FACTORS

There have been no material changes to the risk factors previously disclosed in the Company’s Form 10-K filed with the SEC on February 24, 2012.

ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

None.

ITEM 3.  Defaults Upon Senior Securities.

Item 3, Defaults Upon Senior Securities, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

ITEM 4.  Mine Safety Disclosures.

N/A

ITEM 5.  Other Information.

None.

42

ITEM 6.  Exhibits.

The following exhibits are filed as part of this Quarterly Report on Form 10-Q:

10.1	First Amendment to Eighth Amended and Restated Revolving Credit Agreement dated March 26, 2012, among the Company as borrower, and the lenders party thereto (Filed as Exhibit 10.1 to Southern Union's Current Report on Form 8-K filed on August 16, 2012 and incorporated herein by reference.)
31.1	Certificate by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certificate by Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
32.2	Certificate by Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document  *
101.SCH	XBRL Taxonomy Extension Schema Document  *
101.CAL	XBRL Taxonomy Calculation Linkbase Document  *
101.DEF	XBRL Taxonomy Extension Definitions Document  *
101.LAB	XBRL Taxonomy Label Linkbase Document  *
101.PRE	XBRL Taxonomy Presentation Linkbase Document  *

* XBRL information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.

43

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.

		SOUTHERN UNION COMPANY
		(Registrant)
Date:	November 8, 2012	By:	/s/   MARTIN SALINAS, JR.
			Martin Salinas, Jr.
			Chief Financial Officer (duly authorized to sign on behalf of the registrant)

44

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Kelcy L. Warren, certify that:

(1) I have reviewed this Report on Form 10-Q of Southern Union Company;

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

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

(4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date: November 8, 2012

/s/ KELCY L. WARREN

Kelcy L. Warren

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Martin Salinas, Jr., certify that:

(1) I have reviewed this Report on Form 10-Q of Southern Union Company;

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

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

(4) The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date: November 8, 2012

/s/ MARTIN SALINAS, JR.

Martin Salinas, Jr.

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-Q of Southern Union Company (the “Company”) for the quarter ended June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ KELCY L. WARREN

Kelcy L. Warren

Chief Executive Officer

November 8, 2012

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-Q of Southern Union Company (the “Company”) for the quarter ended June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Martin Salinas, Jr., Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ MARTIN SALINAS, JR.

Martin Salinas, Jr.

Chief Financial Officer

November 8, 2012

This Certification is being furnished solely to accompany the Report pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and shall not be incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Report, irrespective of any general incorporation language contained in such filing.

A signed original of this written statement required by Section 906, or other documents authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Related Party Transactions 1 (Details) (Successor [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended
	Sep. 30, 2012	Sep. 30, 2012
Successor [Member]
Related Party Transaction [Line Items]
Operating revenues - ETE	$ 10,180	$ 19,076
Cost of natural gas and other energy	4,688	13,170
Operating, maintenance and general	20,235	23,537
Interest expense	3,487	3,351
Losses from unconsolidated investments	$ (1,065)	$ (381)

XML

Reportable Segments 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member] Transportation and Storage [Member]	Sep. 30, 2012 Successor [Member] Transportation and Storage [Member]	Sep. 30, 2012 Successor [Member] Gathering and Processing [Member]	Sep. 30, 2012 Successor [Member] Gathering and Processing [Member]	Sep. 30, 2012 Successor [Member] Distribution [Member]	Sep. 30, 2012 Successor [Member] Distribution [Member]	Sep. 30, 2012 Successor [Member] Total segment [Member]	Sep. 30, 2012 Successor [Member] Total segment [Member]	Sep. 30, 2012 Successor [Member] Corporate and other activities [Member]	Sep. 30, 2012 Successor [Member] Corporate and other activities [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Dec. 31, 2011 Predecessor [Member]	Mar. 25, 2012 Predecessor [Member] Transportation and Storage [Member]	Sep. 30, 2011 Predecessor [Member] Transportation and Storage [Member]	Sep. 30, 2011 Predecessor [Member] Transportation and Storage [Member]	Dec. 31, 2011 Predecessor [Member] Transportation and Storage [Member]	Mar. 25, 2012 Predecessor [Member] Gathering and Processing [Member]	Sep. 30, 2011 Predecessor [Member] Gathering and Processing [Member]	Sep. 30, 2011 Predecessor [Member] Gathering and Processing [Member]	Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member]	Mar. 25, 2012 Predecessor [Member] Distribution [Member]	Sep. 30, 2011 Predecessor [Member] Distribution [Member]	Sep. 30, 2011 Predecessor [Member] Distribution [Member]	Dec. 31, 2011 Predecessor [Member] Distribution [Member]	Mar. 25, 2012 Predecessor [Member] Total segment [Member]	Sep. 30, 2011 Predecessor [Member] Total segment [Member]	Sep. 30, 2011 Predecessor [Member] Total segment [Member]	Dec. 31, 2011 Predecessor [Member] Total segment [Member]	Mar. 25, 2012 Predecessor [Member] Corporate and other activities [Member]	Sep. 30, 2011 Predecessor [Member] Corporate and other activities [Member]	Sep. 30, 2011 Predecessor [Member] Corporate and other activities [Member]	Dec. 31, 2011 Predecessor [Member] Corporate and other activities [Member]
Segment Reporting Information [Line Items]
Operating revenues from external customers	$ 477,896	$ 990,078	$ 188,481	$ 387,173	$ 213,382	$ 430,215	$ 73,237	$ 167,742	$ 475,100	$ 985,130	$ 2,796	$ 4,948	$ 633,649	$ 617,211	$ 1,995,640		$ 193,921	$ 192,699	$ 584,753		$ 246,463	$ 339,658	$ 891,825		$ 190,499	$ 80,763	$ 506,412		$ 630,883	$ 613,120	$ 1,982,990		$ 2,766	$ 4,091	$ 12,650
Segment Adjusted EBITDA	169,178	274,721	122,486	205,130	25,296	36,155	22,461	35,907			(1,065)	(2,471)	225,753	247,300	723,115		185,706	199,952	570,072		25,338	34,234	94,440		33,554	14,369	58,673						(18,845)	(1,255)	(70)
Depreciation and amortization	(75,710)	(154,909)											(56,544)	(59,327)	(177,949)
Unrealized gains on unhedged derivative activities	0	0											0	5,130	(9,283)
Net gain on curtailment of OPEB plans		15,332											0		0
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(7,256)	(12,116)											(1,350)	(2,926)	(7,580)
Other Income (Expense) affecting Segment Adjusted EBITDA	(755)	(564)											284	191	557
Earnings from unconsolidated investments	(1,065)	(381)											16,160	26,686	78,435
Adjusted EBITDA attributable to unconsolidated investments	(3,808)	(7,673)											(61,108)	(79,651)	(194,723)
Interest expense	(34,639)	(96,323)											(50,407)	(54,925)	(165,429)
Income before income tax expense	45,945	18,087											72,788	82,478	247,143
Income tax (benefit) expense	(28,959)	(27,883)											(22,871)	(24,446)	(68,676)
Net income (loss)	16,986	(9,796)											49,917	58,032	178,467
Total assets	$ 9,879,812	$ 9,879,812	$ 5,695,305	$ 5,695,305	$ 2,820,127	$ 2,820,127	$ 1,249,047	$ 1,249,047	$ 9,764,479	$ 9,764,479	$ 115,333	$ 115,333				$ 8,270,859				$ 5,288,967				$ 1,742,516				$ 1,075,253				$ 8,106,736				$ 164,123

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Derivative Instrument and Hedging Activities 1 Narrative (Details) (USD $)														9 Months Ended						9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Term Loan Due March 2012 [Member]	Sep. 30, 2012 Successor [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Southern Union [Member] Junior Subordinated Debt [Member]		Dec. 31, 2011 Successor [Member] Southern Union [Member] Junior Subordinated Debt [Member]		Sep. 30, 2012 LIBOR [Member] Southern Union [Member] Junior Subordinated Debt [Member]	Sep. 30, 2012 Interest Rate Swap [Member]	Dec. 31, 2011 Interest Rate Swap [Member]	Dec. 31, 2011 Interest Rate Swap [Member] Interest Rate Swap, Ten Year Period [Member]	Dec. 31, 2011 Interest Rate Swap [Member] Interest Rate Swap, Five Year Period [Member]	Sep. 30, 2012 Interest Rate Swap [Member] LIBOR [Member] Junior Subordinated Debt [Member]	Sep. 30, 2012 Natural gas price swaps [Member] Gathering and Processing [Member]	Sep. 30, 2012 Natural gas price swaps [Member] Year 2012 [Member] Gathering and Processing [Member] MMbtu	Sep. 30, 2012 Natural gas price swaps [Member] Year 2012 [Member] MMBtus [Member] Gathering and Processing [Member] MMbtu	Sep. 30, 2012 Natural gas price swaps [Member] Year 2013 [Member] Gathering and Processing [Member] MMbtu	Sep. 30, 2012 Natural gas price swaps [Member] Year 2013 [Member] MMBtus [Member] Gathering and Processing [Member] MMbtu	Sep. 30, 2012 Natural gas price swaps [Member] Year 2014 [Member] Gathering and Processing [Member] MMbtu	Sep. 30, 2012 NGL price swaps [Member] Gathering and Processing [Member]	Sep. 30, 2012 NGL price swaps [Member] Year 2012 [Member] Gallons [Member] Gathering and Processing [Member] gallons	Sep. 30, 2012 NGL price swaps [Member] Year 2012 [Member] MMBtus [Member] Gathering and Processing [Member] MMbtu
Derivative [Line Items]
Long-term debt			$ 1,339,997,000	$ 600,000,000	[1]	$ 600,000,000	[1]
Derivative notional amount									455,000,000	525,000,000	450,000,000	75,000,000
Debt instrument, three month LIBOR, basis spread on variable rate								3.0175%					3.0175%
Interest rate swap, period (in years)											10 years	5 years
Derivative fixed interest rate									3.63%
Derivative notional amount, nonmonetary (in MMBtu or gallons)															3,660,000	2,760,000	12,130,000	10,037,500	2,640,000		16,449,048	2,319,300
Debt, face amount		455,000,000
Net, after-tax losses in accumulated other comprehensive income														700,000						6,100,000
Derivative net liability position, aggregate fair value	$ 3,200,000

[1] Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly. See Interest Rate Swaps below for more information regarding the interest rate on these notes.

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Regulation and Rates Narrative (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended				3 Months Ended
	Feb. 10, 2010 Missouri Gas Energy [Member]	Apr. 02, 2009 Missouri Gas Energy [Member]	Nov. 13, 2009 New England Gas Company [Member]	Sep. 15, 2008 New England Gas Company [Member]	Mar. 31, 2012 New England Gas Company [Member]
Regulated Operations [Line Items]
Base rate increase		$ 32.4
Revenue increase authorized	16.2
Percent residential small general service customers	99.00%
Percent residential small general service net operating revenues	91.00%
Recovery amount requested based on previous years' earnings below return on equity of 7%			1.7	4.0
Recovery percentage requested of earnings below stated return on equity			50.00%	50.00%
Remand Recovery Floor				7.00%
Adjusted Earnings Share Adjustment recovery requested				4.1
Earnings Share Adjustment recovery amount under investigation			1.7
Earnings Share Adjustment (ESA) recovery approved					$ 4

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Taxes on Income 2 Narrative (Details)	9 Months Ended
	Sep. 30, 2012
Income Tax Disclosure [Abstract]
U.S. federal income tax statutory rate	35.00%

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Fair Value Measurement (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Schedule Of Fair Value Assets And Liabilities Measured On Recurring Basis

The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the date indicated:

	Fair Value Measurements at September 30, 2012
	Fair Value Total		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	6,589	$	—	$	6,589	$	—
Total	$	6,589	$	—	$	6,589	$	—
Liabilities:
Commodity derivatives	$	15,093	$	—	$	15,093	$	—
Interest-rate swap derivatives	80,452		—		80,452		—
Total	$	95,545	$	—	$	95,545	$	—

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Reportable Segments (Policies)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Segment Reporting, Policy

The Company’s primary operating segments, which are individually disclosed as its reportable business segments, are:  Transportation and Storage, Gathering and Processing, and Distribution.  These operating segments are organized for segment reporting purposes based on the way internal managerial reporting presents the results of the Company’s various businesses to its chief operating decision maker for use in determining the performance of the businesses.

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Derivative Instrument and Hedging Activities 3 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended		3 Months Ended			9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]		Mar. 25, 2012 Predecessor [Member]		Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Cash Flow Hedges: Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive income	$ 0	$ 0	[1]	$ 6,174	[1]	$ 50,283	$ 71,031	[1]
Reclassification of unrealized loss from Accumulated other comprehensive income - increase of Interest expense	0	0	[1]	8,085	[1]	5,715	16,881	[1]
Cash Flow Hedges: Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in Accumulated other comprehensive income	(5,526)	5,851	[1]	4,619	[1]	8,434	7,420	[1]
Reclassification of unrealized gain from Accumulated other comprehensive income	6,011	11,547	[1]	2,043	[1]	5,598	14,782	[1]
Economic Hedges: Interest rate contracts: [Abstract]
Change in fair value - increase in interest expense	(4,294)	15,415		0		0	0
Economic Hedges: Commodity contracts - Gathering and Processing:
Change in fair value of hedges - decrease in Operating revenues	0					3,963
Change in fair value of other hedges - decrease in Operating revenues		0		50			27,611
Economic Hedges: Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in Deferred natural gas purchases	$ (10,866)	$ (30,961)		$ (1,957)		$ 10,114	$ (13,658)

[1] The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis. If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim condensed consolidated balance sheet on a net basis and disclosed herein on a gross basis.

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Debt Obligations 2 Narrative (Details) (USD $)			9 Months Ended					9 Months Ended	6 Months Ended
	Sep. 30, 2012 Fair Value of Debt [Member]	Dec. 31, 2011 Fair Value of Debt [Member]	Sep. 30, 2012 Revolver 2012 [Member]	Sep. 30, 2012 Seventh Amended and Restated Credit Agreement [Member]	Sep. 30, 2012 Term Loan Due August 2013 [Member]	Sep. 30, 2012 Term Loan Due June 2012 [Member]	Sep. 30, 2012 Term Loan Due March 2012 [Member]	Sep. 30, 2012 Note payable - ETE [Member]	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Southern Union [Member] 7.20% Junior Subordinated Notes due 2066 [Member]		Dec. 31, 2011 Successor [Member] Southern Union [Member] 7.20% Junior Subordinated Notes due 2066 [Member]		Sep. 30, 2012 Successor [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Panhandle [Member] Senior Notes due 2013 [Member]	Sep. 30, 2012 LIBOR [Member] Southern Union [Member] 7.20% Junior Subordinated Notes due 2066 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 3,520,000,000	$ 3,700,000,000				$ 342,400,000		$ 221,200,000		$ 1,339,997,000	$ 600,000,000	[1]	$ 600,000,000	[1]	$ 1,764,179,000
Senior Notes																250,000,000
Debt, face amount			700,000,000	550,000,000	250,000,000	465,000,000	455,000,000
Debt, Weighted Average Interest Rate			1.83%
Debt instrument, maturity date			May 20, 2016
Debt instrument, LIBOR, basis spread on variable rate																	3.0175%
Debt Instruments Fair Value	3,550,000,000	3,960,000,000
Interest rate								3.75%
Repayments of Long-term Debt								$ 55,000,000	$ 297,000

[1] Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly. See Interest Rate Swaps below for more information regarding the interest rate on these notes.

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ETE Merger and Holdco Transaction - PPA Table (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012 years	Mar. 25, 2012
Business Acquisition [Line Items]
Intangible asset, estimated useful life	17.5
Cash and cash equivalents		$ 36,792
Other current assets		524,246
Property and equipment		6,958,768
Goodwill		2,030,271
Identified intangibles		55,000	[1]
Other noncurrent assets		290,360
Long-term debt, including current portion		(3,333,706)
Deferred income taxes		(1,698,352)
Other liabilities		(950,513)
Total purchase price		3,912,866
Transportation & Storage [Member]
Business Acquisition [Line Items]
Goodwill		1,170,000
Gathering & Processing [Member]
Business Acquisition [Line Items]
Goodwill		598,300
Distribution [Member]
Business Acquisition [Line Items]
Goodwill		251,800
Corporate & Other [Member]
Business Acquisition [Line Items]
Goodwill		$ 10,800

[1] (1) Identified intangibles will be amortized over an estimated life of approximately 17.5 years and are included in deferred charges in the unaudited condensed consolidated balance sheet.

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Commitments and Contingencies 1 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012 Successor [Member]	Dec. 31, 2011 Predecessor [Member]
Environmental Liabilities [Line Items]
Current	$ 4,363	$ 9,353
Noncurrent	24,588	11,635
Total environmental liabilities	$ 28,951	$ 20,988

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Taxes on Income 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Current:
Federal	$ (419)	$ (419)	$ 0	$ (745)	$ (572)
State	2,272	2,754	5	(143)	(7,629)
Total current	1,853	2,335	5	(888)	(8,201)
Deferred:
Federal	25,742	23,928	19,861	21,903	70,507
State	1,364	1,620	3,005	3,431	6,370
Total deferred	27,106	25,548	22,866	25,334	76,877
Total federal and state income tax expense (benefit)	$ 28,959	$ 27,883	$ 22,871	$ 24,446	$ 68,676
Effective tax rate	63.00%	154.00%	31.00%	30.00%	28.00%

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

There have been no changes in the Company’s accounting policies as disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011, except as noted below, as a result of the Company's merger with ETE.

Business Combination Accounting

The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 to our condensed consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

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Debt Obligations 1 (Details) (USD $) In Thousands, unless otherwise specified								9 Months Ended																									12 Months Ended
	Sep. 30, 2012 Successor [Member]		Sep. 30, 2012 Successor [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Line of Credit [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] 7.60% Senior Notes due 2024 [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] 8.25% Senior Notes Due 2029 [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] 7.24% to 9.44% First Mortgage Bonds due 2020 to 2027 [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] 7.20% Junior Subordinated Notes due 2066 [Member] Southern Union [Member]		Dec. 31, 2011 Successor [Member] 7.20% Junior Subordinated Notes due 2066 [Member] Southern Union [Member]		Sep. 30, 2012 Successor [Member] Term Loan due 2013 [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Note Payable [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Unamortized fair value adjustment [Member] Southern Union [Member]	Sep. 30, 2012 Successor [Member] Unamortized fair value adjustment [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Senior Notes due 2013 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] 6.20% Senior Notes due 2017 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] 8.125% Senior Notes due 2019 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] 7.00% Senior Notes due 2029 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] 7.00% Senior Notes due 2018 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Term Loan due 2012 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Term Loan due 2015 [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Net premiums on long-term debt [Member] Panhandle [Member]	Sep. 30, 2012 Successor [Member] Note payable [Member] ETE [Member]	Dec. 31, 2011 Predecessor [Member]		Dec. 31, 2011 Predecessor [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Line of Credit [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] 7.60% Senior Notes due 2024 [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] 8.25% Senior Notes Due 2029 [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] 7.24% to 9.44% First Mortgage Bonds due 2020 to 2027 [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] 7.20% Junior Subordinated Notes due 2066 [Member] Southern Union [Member]		Dec. 31, 2011 Predecessor [Member] Term Loan due 2013 [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] Note Payable [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] Unamortized fair value adjustment [Member] Southern Union [Member]	Dec. 31, 2011 Predecessor [Member] Unamortized fair value adjustment [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Senior Notes due 2013 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] 6.20% Senior Notes due 2017 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] 8.125% Senior Notes due 2019 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] 7.00% Senior Notes due 2029 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] 7.00% Senior Notes due 2018 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Term Loan due 2012 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Term Loan due 2015 [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Net premiums on long-term debt [Member] Panhandle [Member]	Dec. 31, 2011 Predecessor [Member] Note payable [Member] ETE [Member]	Sep. 30, 2012 LIBOR [Member] 7.20% Junior Subordinated Notes due 2066 [Member] Southern Union [Member]	Sep. 30, 2012 Revolver 2012 [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate																																																		1.83%
Long Term Debt Obligations:
Senior Notes						$ 359,765	$ 300,000											$ 300,000	$ 150,000	$ 66,305	$ 400,000										$ 359,765	$ 300,000								$ 250,000	$ 300,000	$ 150,000	$ 66,305	$ 400,000
Long-term Debt			1,339,997	1,764,179				19,500	600,000	[1]	600,000	[1]	0	7,306								0	455,000	0				1,537,011	1,966,615				19,500	600,000	[1]	250,000	7,746								797,386	0	2,924
Unamortized fair value adjustments															53,426	142,874																						0	0
Credit Facilities					251,000																									200,000
Notes Payable - ETE																									166,217																							0
Total consolidated debt obligations	3,521,393																									3,703,626
Less: Current portion of long-term debt	(261,351)																									(343,254)
Less: Short-term debt	166,217	[2]																								200,000	[2]
Total long-term debt	$ 3,093,825																									$ 3,160,372
Debt instrument, three month LIBOR, basis spread on variable rate																																																	3.0175%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum								7.24%																									7.24%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum								9.44%																									9.44%
Debt Instrument, Interest Rate, Stated Percentage						7.60%	8.25%		7.20%								6.05%	6.20%	8.125%	7.00%	7.00%										7.60%	8.25%		7.20%						6.05%	6.20%	8.125%	7.00%	7.00%

[1] Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly. See Interest Rate Swaps below for more information regarding the interest rate on these notes.

[2] (2) The Southern Union Credit Facility was included in short-term debt as of December 31, 2011, but not as of September 30, 2012. See discussion in "Credit Facilities" below.

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Debt Obligations (Tables)

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Schedule Of Debt Instruments

The following table sets forth the debt obligations of Southern Union and Panhandle at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Southern Union Credit Facility	$	251,000	$	200,000
Southern Union:
7.60% Senior Notes due 2024	359,765		359,765
8.25% Senior Notes due 2029	300,000		300,000
7.24% to 9.44% First Mortgage Bonds due 2020 to 2027	19,500		19,500
7.20% Junior Subordinated Notes due 2066 (1)	600,000		600,000
Term Loan due 2013	—		250,000
Note Payable	7,306		7,746
Unamortized fair value adjustments	53,426		—
	1,339,997		1,537,011
Panhandle:
6.05% Senior Notes due 2013	250,000		250,000
6.20% Senior Notes due 2017	300,000		300,000
8.125% Senior Notes due 2019	150,000		150,000
7.00% Senior Notes due 2029	66,305		66,305
7.00% Senior Notes due 2018	400,000		400,000
Term Loan due 2012	—		797,386
Term Loan due 2015	455,000		—
Net premiums on long-term debt	—		2,924
Unamortized fair value adjustments	142,874		—
	1,764,179		1,966,615
Note Payable — ETE	166,217		—
Total debt	3,521,393		3,703,626
Less: Current portion of long term debt	261,351		343,254
Less: Short-term debt (2)	166,217		200,000
Total long-term debt	$	3,093,825	$	3,160,372

⁽¹⁾  Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly.  See Interest Rate Swaps below for more information regarding the interest rate on these notes.

⁽²⁾  The Southern Union Credit Facility was included in short-term debt as of December 31, 2011, but not as of September 30, 2012. See discussion in "Credit Facilities" below

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Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2012

Statement of Income and Comprehensive Income [Abstract]

Schedule Of Comprehensive Income Loss Tax

The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	(18,697	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			2,294
Change in fair value of commodity hedges	(1,992		)	3,039
Reclassification of unrealized gain on commodity hedges into earnings	(2,166		)	(2,017		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			566
Change in other comprehensive income from equity investments	—			23
Total	$	(4,158	)	$	(14,792	)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	2,296		$	(26,454	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,139			6,775
Change in fair value of commodity hedges	2,108			1,665			2,674
Reclassification of unrealized gain on commodity hedges into earnings	(4,161		)	(736		)	(5,327		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			902			1,708
Change in other comprehensive income from equity investments	—			18			66
Total	$	(2,053	)	$	7,284		$	(20,558	)

Schedule of Accumulated Other Comprehensive Income (Loss)

The table below presents the components in accumulated other comprehensive income (loss), net of tax, as of the dates indicated:

	Successor			Predecessor
	September 30, 2012			December 31, 2011
Interest rate hedges	$	—		$	(50,259	)
Commodity hedges	(3,643		)	(11		)
Benefit plans:
Net actuarial loss and prior service costs — pensions	—			(51,845		)
Net actuarial gain and prior service credit — OPEB	—			(14,542		)
Equity investments	(93		)	(2,535		)
Total accumulated other comprehensive income (loss), net of tax	$	(3,736	)	$	(119,192	)

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Benefits 2 Narrative Parentheticals (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Compensation and Retirement Disclosure [Abstract]
Pretax curtailment gain	$ 74.6
Noncurrent refund liability	59.3
Curtailment recognition	$ 15.3

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Benefits (Tables)

9 Months Ended

Sep. 30, 2012

Compensation and Retirement Disclosure [Abstract]

Schedule Of Net Benefit Costs Table

The following tables set forth the components of net periodic benefit cost (credit) of the Company’s pension and postretirement benefit plans for the periods presented below:

	Pension Benefits						Other Postretirement Benefits
	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Three months ended September 30, 2012			Three months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	1,132		$	935		$	188		$	880
Interest cost	2,269			2,526			614			1,446
Expected return on plan assets	(2,994		)	(2,646		)	(1,622		)	(1,450		)
Prior service cost (credit) amortization	—			146			—			(453		)
Actuarial loss (gain) amortization	—			1,984			—			(402		)
	407			2,945			(820		)	21
Regulatory adjustment (2)	2,919			192			726			667
Net periodic benefit cost (credit)	$	3,326		$	3,137		$	(94	)	$	688

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	2,358		$	998		$	2,805		$	411		$	881		$	2,641
Interest cost	4,728			2,095			7,576			1,276			1,254			4,338
Expected return on plan assets	(6,238		)	(2,461		)	(7,939		)	(3,380		)	(1,367		)	(4,349		)
Prior service cost (credit) amortization	—			133			440			—			(409		)	(1,359		)
Actuarial loss (gain) amortization	—			2,308			5,951			—			273			(1,208		)
Curtailment recognition (1)	—			—			—			(15,332		)	—			—
	848			3,073			8,833			(17,025		)	632			63
Regulatory adjustment (2)	5,892			253			575			1,464			657			1,999
Net periodic benefit cost (credit)	$	6,740		$	3,326		$	9,408		$	(15,561	)	$	1,289		$	2,062

⁽¹⁾  Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $74.6 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $59.3 million.  As such, the net curtailment gain recognition was $15.3 million.

⁽²⁾  In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

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Taxes on Income (Tables)

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Income Tax

The following tables summarize the Company’s income taxes for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	(745	)
State	2,272			(143		)
Total	1,853			(888		)
Deferred expense:
Federal	25,742			21,903
State	1,364			3,431
Total	27,106			25,334
Total federal and state income tax expense	$	28,959		$	24,446
Effective tax rate	63		%	30		%

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	—		$	(572	)
State	2,754			5			(7,629		)
Total	2,335			5			(8,201		)
Deferred expense:
Federal	23,928			19,861			70,507
State	1,620			3,005			6,370
Total	25,548			22,866			76,877
Total federal and state income tax expense	$	27,883		$	22,871		$	68,676
Effective tax rate	154		%	31		%	28		%

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Description of Business

9 Months Ended

Sep. 30, 2012

Description of Business [Abstract]

Description of Business

DESCRIPTION OF BUSINESS:

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments as follows:  

• Transportation and Storage — 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 region.

• Gathering and Processing — 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.  

• Distribution — The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

See Note 3 for information related to the Company’s merger with ETE and the completion of the Holdco Transaction.

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Derivative Instrument and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the unaudited interim condensed consolidated balance sheets at the dates indicated:

	Fair Value
	Asset Derivatives				Liability Derivatives
	Successor		Predecessor		Successor		Predecessor
Balance Sheet Location	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	—	$	19,936
Deferred credits	—		—		—		59,789
Commodity contracts — Gathering and Processing:
Natural gas price swaps
Prepayments and other assets	1,498		6,124		—		—
Accounts payable — related parties	—		—		7,135		—
NGL price swaps
Prepayments and other assets	4,323		—		—		1,996
Derivative instruments — liabilities	—		—		—		4,144
	$	5,821	$	6,124	$	7,135	$	85,865
Economic Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	17,310	$	—
Deferred credits	—		—		63,142		—
Commodity contracts — Gathering and Processing:
Other derivative instruments
Derivative instruments — liabilities	—		—		—		50
Commodity contracts — Distribution:
Natural gas price swaps
Other non-current assets	768		—		—		—
Derivative instruments — liabilities	—		—		7,958		34,468
Deferred credits	—		3		—		5,643
	$	768	$	3	$	88,410	$	40,161
Total	$	6,589	$	6,127	$	95,545	$	126,026

The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim condensed consolidated balance sheet on a net basis and disclosed herein on a gross basis.

Derivatives Effect On Income Table

The following tables summarize the location and amount (excluding income tax effects) of derivative instrument gains and losses reported in the Company’s unaudited interim condensed consolidated financial statements for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	50,283
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			5,715
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in accumulated other comprehensive income	(5,526		)	8,434
Reclassification of unrealized gain from accumulated other comprehensive income - increase of operating revenues	6,011			5,598
Economic Hedges:
Interest rate contracts:
Change in fair value - increase ininterest expense	(4,294		)	—
Commodity contracts - Gathering and Processing:
Change in fair value of hedges - decrease in operating revenues	—			3,963
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in deferred natural gas purchases	(10,866		)	10,114

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	6,174		$	71,031
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			8,085			16,881
Commodity contracts - Gathering and Processing:
Change in fair value - increase in accumulated other comprehensive income	5,851			4,619			7,420
Reclassification of unrealized gain from accumulated other comprehensive income	11,547			2,043			14,782
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	15,415			—			—
Commodity contracts - Gathering and Processing:
Change in fair value of other hedges - decrease in operating revenues	—			50			27,611
Commodity contracts - Distribution:
Change in fair value - decrease in deferred natural gas purchases	(30,961		)	(1,957		)	(13,658		)

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Comprehensive Income (Loss) 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Income tax expense included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$ 0	$ 0	$ 2,296	$ (18,697)	$ (26,454)
Reclassification of unrealized loss on interest rate hedges into earnings	0	0	3,139	2,294	6,775
Change in fair value of commodity hedges	(1,992)	2,108	1,665	3,039	2,674
Reclassification of unrealized gain on commodity hedges into earnings	(2,166)	(4,161)	(736)	(2,017)	(5,327)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	0	0	902	566	1,708
Change in other comprehensive income from equity investments	0	0	18	23	66
Income tax expense included in other comprehensive income (loss)	$ (4,158)	$ (2,053)	$ 7,284	$ (14,792)	$ (20,558)

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Commitments and Contingencies 2 Narrative (Details) (USD $)	3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2012 North Attleboro Site [Member]	Sep. 30, 2012 Attorney General of Commonwealth [Member]	Mar. 31, 2012 Jal 4 Facility [Member]	Mar. 31, 2012 Jal 3 Facility [Member]	Sep. 30, 2012 Mercury Release [Member]	Sep. 30, 2012 Accrued Liabilities [Member]	Dec. 31, 2011 Accrued Liabilities [Member]
Commitments And Contingencies [Line Items]
Estimated remediation costs to completion	$ 10,500,000
Legal fees		18,500,000
Level of recovery		50.00%
Reimbursed expert and consultant costs, maximum		150,000
Alleged regulatory violations			500,000	5,500,000
Jugment Range - Minimum					50,000
Jugment Range - Maximum					500,000
Community Service Obligation					12,000,000
Accrued liabilities, litigation and other claim-related						9,300,000	28,300,000
Alleged Violations					$ 750,000

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012 Successor [Member]		Dec. 31, 2011 Predecessor [Member]
Current assets:
Cash and cash equivalents	$ 7,027		$ 23,640
Accounts receivable, net	160,697		270,741
Accounts receivable - affiliates	14,004	[1]	10,467	[1]
Inventories	192,117		204,235
Deferred natural gas purchases	47,596		50,716
Natural gas imbalances - receivable	25,520		54,549
Prepayments and other assets	34,263		42,675
Total current assets	481,224		657,023
Property, plant and equipment:
Plant in service	6,908,730		7,195,747
Construction work in progress	181,301		103,862
Property, plant and equipment, gross	7,090,031		7,299,609
Less: Accumulated depreciation and amortization	(124,877)		(1,573,273)
Net property, plant and equipment	6,965,154		5,726,336
Deferred charges:
Regulatory assets	129,512		57,447
Other deferred charges	80,122		60,407
Total deferred charges	209,634		117,854
Unconsolidated investments	122,932		1,633,289
Goodwill	2,030,271		89,227
Other non-current assets	70,597		47,130
Total assets	9,879,812		8,270,859
Current liabilities:
Current portion of long–term debt	261,351		343,254
Notes payable	0		200,000
Notes payable — related party	166,217	[2]	0	[2]
Accounts payable and accrued liabilities	109,364		193,949
Accounts payable and accrued liabilities - related parties	32,251		178
Federal, state and local taxes payable	49,879		37,127
Accrued interest	41,568		33,837
Natural gas imbalances - payable	98,677		145,212
Derivative instruments	25,267		58,598
Other	109,732		112,135
Total current liabilities	894,306		1,124,290
Long–term debt, less current portion	3,093,825		3,160,372
Deferred credits	349,845		301,709
Accumulated deferred income taxes	1,707,225		1,044,877
Commitments and contingencies
Stockholders equity:
Common stock	0		126,142
Premium on capital stock	3,913,143		1,934,102
Less: Treasury stock	0		(33,228)
Less: Common stock held in trust	0		(10,888)
Deferred compensation plans	0		10,888
Accumulated other comprehensive loss	(3,736)		(119,192)
Retained earnings (accumulated deficit)	(74,796)		731,787
Total stockholders' equity	3,834,611		2,639,611
Total liabilities and stockholders' equity	$ 9,879,812		$ 8,270,859

[1] Primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates.

[2] See Note 6 for more information regarding the note payable to ETE

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Benefits 1 (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended				9 Months Ended		3 Months Ended				9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Successor [Member] Pension Benefits [Member]		Sep. 30, 2012 Successor [Member] Pension Benefits [Member]		Sep. 30, 2012 Successor [Member] Other Postretirement Benefits [Member]		Sep. 30, 2012 Successor [Member] Other Postretirement Benefits [Member]		Mar. 25, 2012 Predecessor [Member] Pension Benefits [Member]		Sep. 30, 2011 Predecessor [Member] Pension Benefits [Member]		Sep. 30, 2011 Predecessor [Member] Pension Benefits [Member]		Mar. 25, 2012 Predecessor [Member] Other Postretirement Benefits [Member]		Sep. 30, 2011 Predecessor [Member] Other Postretirement Benefits [Member]		Sep. 30, 2011 Predecessor [Member] Other Postretirement Benefits [Member]
Net Periodic Benefit Cost:
Service cost		$ 1,132		$ 2,358		$ 188		$ 411		$ 998		$ 935		$ 2,805		$ 881		$ 880		$ 2,641
Interest cost		2,269		4,728		614		1,276		2,095		2,526		7,576		1,254		1,446		4,338
Expected return on plan assets		(2,994)		(6,238)		(1,622)		(3,380)		(2,461)		(2,646)		(7,939)		(1,367)		(1,450)		(4,349)
Prior service cost (credit) amortization		0		0		0		0		133		146		440		(409)		(453)		(1,359)
Actuarial loss (gain) amortization		0		0		0		0		2,308		1,984		5,951		273		(402)		(1,208)
Curtailment recognition	15,300			0	[1]			(15,332)	[1]	0	[1]			0	[1]	0	[1]			0	[1]
Net periodic benefit cost subtotal		407		848		(820)		(17,025)		3,073		2,945		8,833		632		21		63
Regulatory adjustment		2,919	[2]	5,892	[2]	726	[2]	1,464	[2]	253	[2]	192	[2]	575	[2]	657	[2]	667	[2]	1,999	[2]
Net periodic benefit cost		$ 3,326		$ 6,740		$ (94)		$ (15,561)		$ 3,326		$ 3,137		$ 9,408		$ 1,289		$ 688		$ 2,062

[1] Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $74.6 million. Such gain was offset by establishment of a non-current refund liability in the amount of $59.3 million. As such, the net curtailment gain recognition was $15.3 million.

[2] In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	Total	Predecessor [Member] USD ($)	Predecessor [Member] Common Stock [Member] USD ($)	Predecessor [Member] Premium on Capital Stock [Member] USD ($)	Predecessor [Member] Treasury Stock, at cost [Member] USD ($)	Predecessor [Member] Common Stock Held In Trust [Member] USD ($)	Predecessor [Member] Deferred Compensation Plans [Member] USD ($)	Predecessor [Member] Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Predecessor [Member] Retained Earnings (Accumulated Losses) [Member] USD ($)	Successor [Member] USD ($)	Successor [Member] Common Stock [Member] USD ($)	Successor [Member] Premium on Capital Stock [Member] USD ($)	Successor [Member] Treasury Stock, at cost [Member] USD ($)	Successor [Member] Common Stock Held In Trust [Member] USD ($)	Successor [Member] Deferred Compensation Plans [Member] USD ($)	Successor [Member] Accumulated Other Comprehensive Income (Loss) [Member] USD ($)	Successor [Member] Retained Earnings (Accumulated Losses) [Member] USD ($)
Beginning balance at Dec. 31, 2011		$ 2,639,611	$ 126,142	$ 1,934,102	$ (33,228)	$ (10,888)	$ 10,888	$ (119,192)	$ 731,787
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other comprehensive income, net of tax		12,315						12,315
Share-based compensation		1,654		1,654
Restricted stock issuances		(2,864)	186	(186)	(2,864)
Exercise of stock options		84	5	79
Contributions to Trust						(399)	399
Disbursements from Trust						650	(650)
Purchase of treasury stock		(1,450,000)			(1,450,000)
Net income		49,917							49,917
Common stock, par value (in dollars per share)	1	$ 1
Ending balance at Mar. 25, 2012		1,250,717	126,333	1,935,649	(1,486,092)	(10,637)	10,637	(106,877)	781,704	3,912,867		3,912,867
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other comprehensive income, net of tax										(3,736)						(3,736)
Share-based compensation										276		276
Dividends paid on common stock										(65,000)	0	0	0	0	0	0	(65,000)
Net income										(9,796)							(9,796)
Common stock, par value (in dollars per share)										$ 0.01
Ending balance at Sep. 30, 2012										3,834,611		3,913,143				(3,736)	(74,796)
Beginning balance at Jun. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other comprehensive income, net of tax										(7,670)
Net income										16,986
Common stock, par value (in dollars per share)										$ 0.01
Ending balance at Sep. 30, 2012										$ 3,834,611

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Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment

The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:

	Successor		Predecessor
	Three months ended September 30, 2012		Three months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	188,481	$	192,699
Gathering and Processing	213,382		339,658
Distribution	73,237		80,763
Total segment operating revenues	475,100		613,120
Corporate and other activities	2,796		4,091
	$	477,896	$	617,211

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012		Period from January 1, 2012 to March 25, 2012		Nine months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	387,173	$	193,921	$	584,753
Gathering and Processing	430,215		246,463		891,825
Distribution	167,742		190,499		506,412
Total segment operating revenues	985,130		630,883		1,982,990
Corporate and other activities	4,948		2,766		12,650
	$	990,078	$	633,649	$	1,995,640

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	122,486		$	199,952
Gathering and Processing	25,296			34,234
Distribution	22,461			14,369
Corporate and other activities	(1,065		)	(1,255		)
Total Segment Adjusted EBITDA	169,178			247,300
Depreciation and amortization	(75,710		)	(59,327		)
Unrealized gains on unhedged derivative activities	—			5,130
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(7,256		)	(2,926		)
Other, net	(755		)	191
Earnings (losses) from unconsolidated investments	(1,065		)	26,686
Adjusted EBITDA attributable to unconsolidated investments	(3,808		)	(79,651		)
Interest expense	(34,639		)	(54,925		)
Income before income tax expense	45,945			82,478
Income tax expense	(28,959		)	(24,446		)
Net income	$	16,986		$	58,032

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	205,130		$	185,706		$	570,072
Gathering and Processing	36,155			25,338			94,440
Distribution	35,907			33,554			58,673
Corporate and other activities	(2,471		)	(18,845		)	(70		)
Total Segment Adjusted EBITDA	274,721			225,753			723,115
Depreciation and amortization	(154,909		)	(56,544		)	(177,949		)
Unrealized losses on unhedged derivative activities	—			—			(9,283		)
Net gain on curtailment of OPEB plans	15,332			—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(12,116		)	(1,350		)	(7,580		)
Other, net	(564		)	284			557
Earnings (losses) from unconsolidated investments	(381		)	16,160			78,435
Adjusted EBITDA attributable to unconsolidated investments	(7,673		)	(61,108		)	(194,723		)
Interest expense	(96,323		)	(50,407		)	(165,429		)
Income before income tax expense	18,087			72,788			247,143
Income tax expense	(27,883		)	(22,871		)	(68,676		)
Net income (loss)	$	(9,796	)	$	49,917		$	178,467

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Total assets:
Transportation and Storage	$	5,695,305	$	5,288,967
Gathering and Processing	2,820,127		1,742,516
Distribution	1,249,047		1,075,253
Total segment assets	9,764,479		8,106,736
Corporate and other activities	115,333		164,123
Total assets	$	9,879,812	$	8,270,859

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Derivative Insturments and Hedging Activities (Policies)

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives, Policy

The Company is exposed to certain risks in its ongoing business operations.  The primary risks managed by using derivative instruments are interest rate risk and commodity price risk.  Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time.  Natural gas and NGL price swaps as well as call options and NGL processing spread swaps are the principal derivative instruments used by the Company 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.  

The Company recognizes all derivative instruments as assets or liabilities at fair value in the unaudited interim condensed consolidated balance sheets.

These natural gas price swaps and call options are accounted for as economic hedges, with changes in their fair value recorded to deferred natural gas purchases.

During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified intointerest expense in the same periods during which the related interest payments on long-term debt impacted earnings.

These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings.

These NGL price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted NGL sales impact earnings.

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ETE Merger and Holdco Transaction Narrative (Details) (USD $)	9 Months Ended					3 Months Ended								6 Months Ended	3 Months Ended
	Sep. 30, 2012 years	Mar. 25, 2012 ETECommonUnit	Mar. 25, 2012 Final election results [Member]	Mar. 25, 2012 Actively elected [Member]	Mar. 25, 2012 No election [Member]	Mar. 31, 2012 Citrus [Member]	Sep. 30, 2012 Citrus [Member]	Mar. 25, 2012 Citrus [Member]	Oct. 05, 2012 Holdco [Member] ETE [Member]	Oct. 05, 2012 Holdco [Member] ETP [Member]	Mar. 25, 2012 Maximum [Member]	Mar. 25, 2012 Units Acquired for Cash [Member] Final election results [Member]	Mar. 25, 2012 Units Acquired for Equity [Member] Final election results [Member]	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Dec. 31, 2011 Predecessor [Member]	Mar. 25, 2012 Transportation and Storage [Member]	Mar. 25, 2012 Gathering and Processing [Member]	Mar. 25, 2012 Distribution [Member]	Mar. 25, 2012 Corporate and other activities [Member]
Plan Of Merger [Line Items]
Common stock, par value (in dollars per share)		$ 1												$ 0.01	$ 1	$ 1
Cash value of oustanding share		$ 44.25
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		24,900,000
Business Combination, Consideration Transferred		136,800,000
ETE Common Units Issued		178,851
ETE common unit (in units)		1.00
Percentage of maximum cash consideration in total consideration		60.00%
Percentage of fluctuation in common units allowed											50.00%
Percentage of shares, payable in cash			54.00%
Shares elected and received in cash (in shares)				38,872,598	18,109,262							67,985,929	56,981,860
Percentage of shares, payable in ETE units			46.00%
Percentage owned of Citrus Corp outstanding stock							50.00%
Total merger amount		3,912,866,000						2,000,000,000
Business Combination, Acquisition Related Costs														72,100,000	18,700,000
Merger amount, in cash								1,900,000,000
Merger amount, in common units						105,000,000
Amount of Citrus Merger cash consideration received contributed to Merger Sub in exchange for equity interest in Merger Sub						1,450,000,000
Intangible asset, estimated useful life	17.5
Goodwill		$ 2,030,271,000															$ 1,170,000,000	$ 598,300,000	$ 251,800,000	$ 10,800,000
Post Merger Equity Investment By Affiliate									0.60	0.40

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Commitments and Contingencies (Policies)

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies, Policy

Environmental Matters

The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the condensed consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.

Liabilities for Litigation and Other Claims

In addition to the matters discussed above, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable.  When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made.  As of September 30, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $9.3 million and $28.3 million, respectively.  Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Cash flows from operating activities:
Net income (loss)	$ (9,796)	$ 49,917	$ 178,467
Adjustments to reconcile net earnings to net cash flows provided by operating activities:
Depreciation and amortization	154,909	56,544	177,949
Deferred income taxes	25,548	22,866	76,877
Provision for bad debts	5,678	1,013	12,433
Amortization of costs charged to interest	(16,642)	1,165	4,342
Net gain on curtailment of OPEB plans	(15,332)	0	0
Unrealized loss on derivatives	15,415	0	9,283
Share-based compensation expense	276	1,654	7,580
Earnings from unconsolidated investments, net of cash distributions	4,749	(16,160)	(75,105)
Changes in operating assets and liabilities, net of Merger impact	(187,450)	79,919	59,068
Net cash flows provided by (used in) operating activities	(22,645)	196,918	450,894
Cash flows from investing activities:
Additions to property, plant and equipment	(138,229)	(60,062)	(226,178)
Loan to unconsolidated investments	0	0	(72,000)
Loan repayment from unconsolidated investments	0	37,000	35,000
Proceeds from Citrus Merger	0	1,895,000	0
Plant retirements and other	(2,875)	(2,252)	(1,892)
Net cash flows provided by (used in) investing activities	(141,104)	1,869,686	(265,070)
Cash flows from financing activities:
Issuance of long-term debt	0	455,000	0
Renewal cost for credit facilities and issuance cost of debt	(1,708)	(1,803)	(2,162)
Dividends paid on common stock	(65,000)	(18,726)	(56,099)
Note payable - related party	221,217	0	0
Repayment of note payable-related party	(55,000)	0	0
Repayment of long-term debt obligation	(297)	(1,047,529)	(421)
Net change in revolving credit facilities	38,614	12,386	(131,648)
Purchase of treasury stock	0	(1,450,000)	0
Other	(3,842)	(2,780)	3,321
Net cash flows provided by (used in) financing activities	133,984	(2,053,452)	(187,009)
Change in cash and cash equivalents	(29,765)	13,152	(1,185)
Cash and cash equivalents at beginning of period	36,792	23,640	3,299
Cash and cash equivalents at end of period	$ 7,027	$ 36,792	$ 2,114

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PARENTHETICAL DISCLOSURE OF CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011 Predecessor [Member]	Sep. 30, 2012 Successor [Member]
Allowance for doubtful accounts	$ 2,325	$ 1,352
Common stock, par value (in dollars per share)	$ 1	$ 0.01
Common stock, shares authorized (in shares)	200,000	200,000
Common stock, shares issued (in shares)	126,142	1
Treasury stock (in shares)	1,298,000	0
Common stock, shares held in trust (in shares)	581,000	1,000

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Fair Value Measurement

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

FAIR VALUE MEASUREMENT:

The following table sets forth the Company’s assets and liabilities that are measured at fair value on a recurring basis at the date indicated:

	Fair Value Measurements at September 30, 2012
	Fair Value Total		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	6,589	$	—	$	6,589	$	—
Total	$	6,589	$	—	$	6,589	$	—
Liabilities:
Commodity derivatives	$	15,093	$	—	$	15,093	$	—
Interest-rate swap derivatives	80,452		—		80,452		—
Total	$	95,545	$	—	$	95,545	$	—

The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps.  The pricing models also adjust for nonperformance risk associated with the counterparty or the Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value at September 30, 2012 or December 31, 2011 and there were no transfers between levels.

The approximate fair values of the Company’s cash and cash equivalents, accounts receivable and accounts payable are equal to book value, due to their short-term nature.

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Document And Entity Information In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Nov. 01, 2012
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Entity Registrant Name	Southern Union Co
Entity Central Index Key	0000203248
Document Period End Date	Sep. 30, 2012
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

XML

Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES:

Environmental Matters

The Company’s operations are subject to federal, state and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

Environmental Remediation

Transportation and Storage Segment

Panhandle is responsible for environmental remediation at certain sites on its natural gas transmission systems for contamination resulting from the past use of lubricants containing PCBs in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has implemented a program to remediate such contamination.  The primary remaining remediation activity on the Panhandle systems is associated with past use of paints containing PCBs or PCB impacts to equipment surfaces and to a building at one location.  The PCB assessments are ongoing and the related estimated remediation costs are subject to further change.

Other remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility.  The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Panhandle could potentially be held responsible for contamination caused by other parties. In some instances, Panhandle may share liability associated with contamination with other PRPs.  Panhandle may also benefit from contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

The Company’s environmental remediation activities are undertaken in cooperation with and under the oversight of appropriate regulatory agencies, enabling the Company under certain circumstances to take advantage of various voluntary cleanup programs in order to perform the remediation in the most effective and efficient manner.

Gathering and Processing Segment

SUGS is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons.  SUGS has a program to remediate such contamination.  The remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations.

Distribution Segment

The Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment.  Significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former MGPs and sites associated with the operation and disposal activities of former MGPs that produced a fuel known as “town gas.” Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

North Attleboro MGP Site in Massachusetts (North Attleboro Site).  In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  Assessment activities have recently been completed and it is estimated that the Company will spend approximately$10.5 million over the next several years to complete remediation activities at the North Attleboro Site, as well as maintain the engineered barrier constructed in 2008 at the upland portion of the site.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in regulatory assets in the unaudited interim condensed consolidated balance sheets.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the condensed consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Current	$	4,363	$	9,353
Noncurrent	24,588		11,635
Total environmental liabilities	$	28,951	$	20,988

Litigation and Other Claims

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, the Company 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.  The Company 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 (AG) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with the Company’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling $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, the Company’s former Vice Chairman, President and COO, joined the Company’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 the Company’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  The Company has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of the Company’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by the Company 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.  The Company believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, the Company 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 NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities.  The NMED has issued amended compliance orders (COs) 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 COs were delayed to allow the parties to pursue substantive settlement discussions.  SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations.  The Company has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

Litigation Relating to the Merger with ETE

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 333^rd Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The plaintiff alleged that the defendants breached their fiduciary duties to Southern Union’s stockholders or aided and abetted breaches of fiduciary duties in connection with the Merger.  The petition alleged that the Merger involves an unfair price and an inadequate sales process and that defendants entered into the transaction to benefit themselves personally.  The petition sought injunctive relief, including an injunction of the Merger, attorneys’ and other fees and costs, indemnification and other relief.

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 11^th Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, Southern Union, and ETE.  The plaintiff alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted those alleged breaches.  The petition alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The petition sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On June 28, 2011, and August 19, 2011, amended petitions were filed in the Magda and Jaroslawicz actions, respectively, naming the same defendants and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  The two Texas cases have been consolidated with the following style: In re:  Southern Union Company; Cause No. 2011-37091, in the 333^rd 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.  The 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 and further claimed that ETE aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors should deem a competing proposal made by The Williams Companies, Inc. (Williams) to be superior.  The complaint sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

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.  The complaints named as defendants the members of the Southern Union Board, Southern Union, ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that ETE aided and abetted those alleged breaches.  The complaints alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors must give full consideration to the Williams proposal.  The complaints sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

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.  The complaint named as defendants the members of the Southern Union Board, Southern Union ETE and Merger Sub.  The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the amended Merger agreement and that Southern Union, ETE and Merger Sub aided and abetted those alleged breaches.  The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that the terms of the amended Merger agreement are preclusive.  The complaint sought injunctive relief, including an injunction of the 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, 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 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 seeks injunctive relief, including an injunction of the 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 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 of voluntary dismissal of all claims without prejudice with the Delaware Court of Chancery.  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, captioned In re Southern Union Company, and docketed at Cause No. 2011-37091.

The Company has not recorded an accrued liability, believes the allegations of all the foregoing actions related to the Merger with ETE 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 Energy Transfer Partners, GP, L.P. (ETP GP), Energy Transfer Partners, LLC (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 assets to AmeriGas Partners, L.P. (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.

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 is not currently set.

Mercury Release

In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (District Court) alleging violation of permitting requirements under the federal RCRA and notification requirements under the Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. Trial commenced on September 22, 2008, and on October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On October 2, 2009, the District Court imposed a fine of $6 million and a payment of $12 million in community service.

On December 22, 2010, the United States Court of Appeals for the First Circuit (First Circuit) affirmed the conviction and the sentence. On February 17, 2011, the First Circuit denied the Company's petition for en banc rehearing.  The Company, on October 31, 2011, filed a petition for a writ of certiorari review by the United States Supreme Court (Supreme Court), which review was granted and the case was heard by the Supreme Court on March 19, 2012.

On June 21, 2012, the United States Supreme Court reversed the First Circuit, holding that the sentence imposed on the Company was unconstitutional, and remanded the case back to the District Court for further proceeding consistent with that holding.

On July 17, 2012, the Government moved for “clarification” of the First Circuit's December 22, 2010 decision urging the First Circuit to find that, in addition to resolving whether (i) the alternative fine statute increases the maximum fine that may be imposed on the Company from $50,000 to $500,000; (ii) the $12 million community service obligation is a fine or restitution; and (iii) a new jury should be empanelled to hear evidence regarding the number of days RCRA was violated.

On July 26, 2012, the First Circuit vacated the fine imposed by the District Court and remanded the matter to the District Court for resentencing consistent with the Supreme Court's opinion. In the same order, the First Circuit denied without prejudice the Government's motion for clarification, holding that the issues raised by the Government in its July 17, 2012 motion could be addressed by the parties on remand. Accordingly, the Government has petitioned the District Court for consideration of the same issues with the hearing scheduled for December 3, 2012. A ruling against the Company would likely result in a judgment of up to approximately $750,000.

Liabilities for Litigation and Other Claims

In addition to the matters discussed above, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.

The Company records accrued liabilities for litigation and other claim costs when management believes a loss is probable and reasonably estimable.  When management believes there is at least a reasonable possibility that a material loss or an additional material loss may have been incurred, the Company discloses (i) an estimate of the possible loss or range of loss in excess of the amount accrued; or (ii) a statement that such an estimate cannot be made.  As of September 30, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $9.3 million and $28.3 million, respectively.  Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

Regulation and Rates.  See Note 13 for potential contingent matters associated with the Company’s regulated operations.

Unclaimed Property Audits.  The Company is subject to the laws and regulations of states and other jurisdictions concerning the identification, reporting and escheatment (the transfer of property to the state) of unclaimed or abandoned funds, and is subject to audit and examination for compliance with these requirements.  The Company is currently being examined by a third party auditor on behalf of nine states for compliance with unclaimed property laws.

Air Quality Control

Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.  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.  The Company is reviewing the new standards to determine the impact on its operations.

Transportation and Storage Segment.  In August 2010, the EPA finalized a rule that requires reductions in a number of pollutants, including formaldehyde and carbon monoxide, for certain engines regardless of size at Area Sources (sources that emit less than 10 tons per year of any one Hazardous Air Pollutant (HAP) or 25 tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit 10 tons per year or more of any one HAP or 25 tons per year of all HAPs).  Compliance is required by October 2013.  It is anticipated that the limits adopted in this rule will be used in a future EPA rule that is scheduled to be finalized in 2013, with compliance required in 2016.  This future rule is expected to require reductions in formaldehyde and carbon monoxide emissions from engines greater than 500 horsepower at Major Sources.

Nitrogen oxides are the primary air pollutant from natural gas-fired engines.  Nitrogen oxide emissions may form ozone in the atmosphere.  In 2008, the EPA lowered the ozone standard to 75 ppbwith compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to 60 to 70 ppb in lieu of the 75 ppb standard, with compliance required in 2014 or later.  In September 2011, the EPA decided to rescind the proposed lower ozone standard and begin the process to implement the 75 ppb ozone standard established in 2008.

In January 2010, the EPA finalized a 100 ppb one-hour nitrogen dioxide standard.  The rule requires the installation of new nitrogen dioxide monitors in urban communities and roadways by 2013.  This new monitoring may result in additional nitrogen dioxide non-attainment areas.  In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

The Company is currently reviewing the potential impacts of the August 2010 Area Source National Emissions Standards for Hazardous Air Pollutants rule, implementation of the 2008 ozone standard and the new nitrogen dioxide standard on operations in its Transportation and Storage and Gathering and Processing segments and the potential costs associated with the installation of emission control systems on its existing engines.  The ultimate costs associated with these activities cannot be estimated with any certainty at this time, but the Company believes, based on the current understanding of the current and proposed rules, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

The KDHE set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  Previously, it was anticipated that these measures would be revised to conform to the requirements of the EPA ozone standard discussed above.  KDHE recently indicated that the Kansas City area will be designated as attainment for the ozone standard in 2012, and will not be pursuing any emissions reductions from PEPL’s operations unless there are changes in the future regarding the status of the Kansas City area.

Gathering and Processing Segment.  The Texas Commission on Environmental Quality recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more.  If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard.  This may potentially affect three SUGS recovery units in Texas.  It is unclear at this time how the NMED will address the sulfur dioxide standard.

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Operating revenues	$ 477,896	$ 990,078	$ 633,649	$ 617,211	$ 1,995,640
Operating expenses:
Cost of natural gas and other energy	180,733	374,220	311,270	304,535	1,045,742
Operating, maintenance and general	121,325	306,606	134,921	125,710	370,562
Depreciation and amortization	75,710	154,909	56,544	59,327	177,949
Revenue-related taxes	3,835	8,370	9,867	4,268	26,835
Taxes, other than on income and revenues	14,575	31,304	14,296	12,845	40,972
Total operating expenses	396,178	875,409	526,898	506,685	1,662,060
Operating income	81,718	114,669	106,751	110,526	333,580
Other income (expenses):
Interest expense	(34,639)	(96,323)	(50,407)	(54,925)	(165,429)
Earnings from unconsolidated investments	(1,065)	(381)	16,160	26,686	78,435
Other, net	(69)	122	284	191	557
Total other expenses, net	(35,773)	(96,582)	(33,963)	(28,048)	(86,437)
Income (loss) before income taxes	45,945	18,087	72,788	82,478	247,143
Income tax expense (benefit)	28,959	27,883	22,871	24,446	68,676
Net income (loss)	$ 16,986	$ (9,796)	$ 49,917	$ 58,032	$ 178,467

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Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2012

Statement of Income and Comprehensive Income [Abstract]

Comprehensive Income

COMPREHENSIVE INCOME (LOSS):

The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	(18,697	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			2,294
Change in fair value of commodity hedges	(1,992		)	3,039
Reclassification of unrealized gain on commodity hedges into earnings	(2,166		)	(2,017		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			566
Change in other comprehensive income from equity investments	—			23
Total	$	(4,158	)	$	(14,792	)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	2,296		$	(26,454	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,139			6,775
Change in fair value of commodity hedges	2,108			1,665			2,674
Reclassification of unrealized gain on commodity hedges into earnings	(4,161		)	(736		)	(5,327		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			902			1,708
Change in other comprehensive income from equity investments	—			18			66
Total	$	(2,053	)	$	7,284		$	(20,558	)

The table below presents the components in accumulated other comprehensive income (loss), net of tax, as of the dates indicated:

	Successor			Predecessor
	September 30, 2012			December 31, 2011
Interest rate hedges	$	—		$	(50,259	)
Commodity hedges	(3,643		)	(11		)
Benefit plans:
Net actuarial loss and prior service costs — pensions	—			(51,845		)
Net actuarial gain and prior service credit — OPEB	—			(14,542		)
Equity investments	(93		)	(2,535		)
Total accumulated other comprehensive income (loss), net of tax	$	(3,736	)	$	(119,192	)

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Related Party Transactions

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

RELATED PARTY TRANSACTIONS:

The following table provides a summary of the related party balances included in our condensed consolidated balance sheets at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Investment in ETP	$	100,182	$	—
Accounts receivable — affiliates (1)	14,004		10,467
Note payable — ETE (2)	166,217		—
Accounts payable — affiliates (3)	32,251		178

⁽¹⁾  Primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates.

⁽²⁾  See Note 6 for more information regarding the note payable to ETE.

⁽³⁾  Primarily related to various administrative and operating costs paid by affiliates on behalf of the Company.

The following table provides a summary of the related party activity included in our condensed consolidated statements of operations. Prior period amounts were not included as they were immaterial.

	Successor
	Three months ended September 30, 2012			Period from Acquisition (March 26, 2012) to September 30, 2012
Operating revenues — ETE	$	10,180		$	19,076
Cost of natural gas and other energy	4,688			13,170
Operating, maintenance and general	20,235			23,537
Interest expense	3,487			3,351
Losses from unconsolidated investments	(1,065		)	(381		)

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Fair Value Measurement (Policies)

9 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments, Policy

The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount.  The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu.  The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps.  The pricing models also adjust for nonperformance risk associated with the counterparty or the Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates.  The Company did not have any Level 3 instruments measured at fair value at September 30, 2012 or December 31, 2011 and there were no transfers between levels.

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Reportable Segments

9 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

The Company’s primary operating segments, which are individually disclosed as its reportable business segments, are:  Transportation and Storage, Gathering and Processing, and Distribution.  These operating segments are organized for segment reporting purposes based on the way internal managerial reporting presents the results of the Company’s various businesses to its chief operating decision maker for use in determining the performance of the businesses.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus (through March 26, 2012, the date of the Citrus Merger).  The Gathering and Processing segment operations are conducted through SUGS.  The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts, through its Missouri Gas Energy and New England Gas Company operating divisions, respectively. See Note 1 for additional information associated with the Company’s reportable segments.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the nine months ended September 30, 2012 and 2011.

The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other activities.  Corporate and other activities consist of unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

The Company previously reported segment EBIT as a measure of segment performance.  Subsequent to the ETE Merger, the chief operating decision maker assesses performance of the Company’s business based on Segment Adjusted EBITDA.  The Company defines Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, unrealized gains and losses on unhedged derivative activities, accretion expense and amortization of regulatory assets and other non-operating income or expense items.  Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company’s proportionate ownership.  Based on the change in its segment performance measure, the Company has recast the presentation of its segment results for the prior periods to be consistent with the current period presentation. Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

The following tables set forth certain selected financial information for the Company’s segments for the periods presented or at the dates indicated:

	Successor		Predecessor
	Three months ended September 30, 2012		Three months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	188,481	$	192,699
Gathering and Processing	213,382		339,658
Distribution	73,237		80,763
Total segment operating revenues	475,100		613,120
Corporate and other activities	2,796		4,091
	$	477,896	$	617,211

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012		Period from January 1, 2012 to March 25, 2012		Nine months ended September 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	387,173	$	193,921	$	584,753
Gathering and Processing	430,215		246,463		891,825
Distribution	167,742		190,499		506,412
Total segment operating revenues	985,130		630,883		1,982,990
Corporate and other activities	4,948		2,766		12,650
	$	990,078	$	633,649	$	1,995,640

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	122,486		$	199,952
Gathering and Processing	25,296			34,234
Distribution	22,461			14,369
Corporate and other activities	(1,065		)	(1,255		)
Total Segment Adjusted EBITDA	169,178			247,300
Depreciation and amortization	(75,710		)	(59,327		)
Unrealized gains on unhedged derivative activities	—			5,130
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(7,256		)	(2,926		)
Other, net	(755		)	191
Earnings (losses) from unconsolidated investments	(1,065		)	26,686
Adjusted EBITDA attributable to unconsolidated investments	(3,808		)	(79,651		)
Interest expense	(34,639		)	(54,925		)
Income before income tax expense	45,945			82,478
Income tax expense	(28,959		)	(24,446		)
Net income	$	16,986		$	58,032

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	205,130		$	185,706		$	570,072
Gathering and Processing	36,155			25,338			94,440
Distribution	35,907			33,554			58,673
Corporate and other activities	(2,471		)	(18,845		)	(70		)
Total Segment Adjusted EBITDA	274,721			225,753			723,115
Depreciation and amortization	(154,909		)	(56,544		)	(177,949		)
Unrealized losses on unhedged derivative activities	—			—			(9,283		)
Net gain on curtailment of OPEB plans	15,332			—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(12,116		)	(1,350		)	(7,580		)
Other, net	(564		)	284			557
Earnings (losses) from unconsolidated investments	(381		)	16,160			78,435
Adjusted EBITDA attributable to unconsolidated investments	(7,673		)	(61,108		)	(194,723		)
Interest expense	(96,323		)	(50,407		)	(165,429		)
Income before income tax expense	18,087			72,788			247,143
Income tax expense	(27,883		)	(22,871		)	(68,676		)
Net income (loss)	$	(9,796	)	$	49,917		$	178,467

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Total assets:
Transportation and Storage	$	5,695,305	$	5,288,967
Gathering and Processing	2,820,127		1,742,516
Distribution	1,249,047		1,075,253
Total segment assets	9,764,479		8,106,736
Corporate and other activities	115,333		164,123
Total assets	$	9,879,812	$	8,270,859

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Taxes on Income

9 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Taxes on Income

TAXES ON INCOME:

The following tables summarize the Company’s income taxes for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	(745	)
State	2,272			(143		)
Total	1,853			(888		)
Deferred expense:
Federal	25,742			21,903
State	1,364			3,431
Total	27,106			25,334
Total federal and state income tax expense	$	28,959		$	24,446
Effective tax rate	63		%	30		%

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Current expense (benefit):
Federal	$	(419	)	$	—		$	(572	)
State	2,754			5			(7,629		)
Total	2,335			5			(8,201		)
Deferred expense:
Federal	23,928			19,861			70,507
State	1,620			3,005			6,370
Total	25,548			22,866			76,877
Total federal and state income tax expense	$	27,883		$	22,871		$	68,676
Effective tax rate	154		%	31		%	28		%

In the predecessor period, the Company’s EITR was generally lower than the U.S. federal income tax statutory rate of 35% primarily due to the expected deductions for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated investment in Citrus.  In the successor period, the earnings from Citrus and the related dividends received deductions will no longer be applicable because of the Company’s contribution of its unconsolidated investment in Citrus to ETP, a subsidiary of ETE.  In the successor period, the Company’s EITR was impacted by non-deductible excess parachute payments resulting from Merger-related employee severance expenses.

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Debt Obligations

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

The following table sets forth the debt obligations of Southern Union and Panhandle at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Southern Union Credit Facility	$	251,000	$	200,000
Southern Union:
7.60% Senior Notes due 2024	359,765		359,765
8.25% Senior Notes due 2029	300,000		300,000
7.24% to 9.44% First Mortgage Bonds due 2020 to 2027	19,500		19,500
7.20% Junior Subordinated Notes due 2066 (1)	600,000		600,000
Term Loan due 2013	—		250,000
Note Payable	7,306		7,746
Unamortized fair value adjustments	53,426		—
	1,339,997		1,537,011
Panhandle:
6.05% Senior Notes due 2013	250,000		250,000
6.20% Senior Notes due 2017	300,000		300,000
8.125% Senior Notes due 2019	150,000		150,000
7.00% Senior Notes due 2029	66,305		66,305
7.00% Senior Notes due 2018	400,000		400,000
Term Loan due 2012	—		797,386
Term Loan due 2015	455,000		—
Net premiums on long-term debt	—		2,924
Unamortized fair value adjustments	142,874		—
	1,764,179		1,966,615
Note Payable — ETE	166,217		—
Total debt	3,521,393		3,703,626
Less: Current portion of long term debt	261,351		343,254
Less: Short-term debt (2)	166,217		200,000
Total long-term debt	$	3,093,825	$	3,160,372

⁽¹⁾  Effective November 1, 2011, the interest rate on the Junior Subordinated Notes changed to a variable rate based upon the three-month LIBOR rate plus 3.0175%, reset quarterly.  See Interest Rate Swaps below for more information regarding the interest rate on these notes.

⁽²⁾  The Southern Union Credit Facility was included in short-term debt as of December 31, 2011, but not as of September 30, 2012. See discussion in "Credit Facilities" below.

Based on the estimated borrowing rates currently available to the Company and its subsidiaries for loans with similar terms and average maturities, the aggregate fair value of the Company's consolidated debt obligations at September 30, 2012 and December 31, 2011 was $3.55 billion and $3.96 billion, respectively. As of September 30, 2012 and December 31, 2011, the aggregate carrying amount of the Company's consolidated debt obligations was $3.52 billion and $3.70 billion, respectively. The fair value of the Company's consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Credit Facilities.  In March 2012, the Company entered into the Eighth Amended and Restated Revolving Credit Agreement with certain banks in the amount of $700 million (Southern Union Credit Facility).  The Southern Union Credit Facility is an amendment, restatement and refinancing of the Company’s $550 million Seventh Amended and Restated Revolving Credit Agreement.  The Southern Union Credit Facility is scheduled to mature on May 20, 2016.  The Company entered into the Southern Union Credit Facility in order to (i) obtain consent to the transactions contemplated by the Merger Agreement, the Citrus Merger Agreement and the Support Agreement; (ii) to increase the amount of the facility from $550 million to $700 million; and (iii) to modify certain covenants.  Borrowings under the Southern Union Credit Facility are available for the Company’s working capital, other general corporate 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 upon the credit rating for the Company’s senior unsecured notes.  The annualized interest rate for the Southern Union Credit Facility was 1.83% at September 30, 2012.

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 or indirect 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.

The Company previously classified borrowings under the Southern Union Credit Facility as short-term debt as the individual borrowings are generally for periods of 15 to 180 days. As of September 30, 2012, such borrowings have been classified as non-current based on the Company's expectation that such borrowings will be refinanced upon maturity. Therefore, the Southern Union Credit Facility is classified in the table above and in the consolidated balance sheet as short-term debt as of December 31, 2011 and as long-term debt as of September 30, 2012.

Term Loans.  In March 2012, the Company retired the $250 million term loan due August 2013 and the $465 million term loan of its indirect wholly owned subsidiary, LNG Holdings, due June 2012 ($342.4 million of which was outstanding) utilizing a combination of the merger consideration received in connection with the Citrus Merger and borrowings under the Southern Union Credit Facility.

In February 2012, the Company 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.

Note Payable – ETE.  On March 26, 2012, the Company received $221.2 million from ETE to pay certain expenses in connection with the Merger, including (i) payments made to employees related to outstanding awards of stock options, stock appreciation rights and restricted stock units; and (ii) payments to certain executives under applicable employment or change in control agreements, which provided for compensation when their employment was terminated in connection with a change in control.  In connection with the receipt of the $221.2 million from ETE, on March 26, 2012, the Company entered into an interest-bearing promissory note payable on or before March 25, 2013.  The interest rate under the promissory note is 3.75% and accrued interest is payable monthly in arrears. A payment of $55.0 million to ETE was made in May 2012.

Panhandle 6.05% Senior Notes due 2013. Panhandle has $250 million of senior notes which mature within the next twelve months.  Panhandle currently expects to refinance all or a portion of the debt upon maturity or, alternatively, to retire all or a portion of the debt with proceeds from repayment of the note receivable from Southern Union.

Interest Rate Swaps.  The Company had interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on a portion of the $600 million Junior Subordinated Notes due 2066 (Junior Subordinated Notes).  See Note 9for more information regarding these swap agreements.

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Benefits

9 Months Ended

Sep. 30, 2012

Compensation and Retirement Disclosure [Abstract]

Benefits

BENEFITS:

Components of Net Periodic Benefit Cost

The following tables set forth the components of net periodic benefit cost (credit) of the Company’s pension and postretirement benefit plans for the periods presented below:

	Pension Benefits						Other Postretirement Benefits
	Successor			Predecessor			Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011			Three months ended September 30, 2012			Three months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	1,132		$	935		$	188		$	880
Interest cost	2,269			2,526			614			1,446
Expected return on plan assets	(2,994		)	(2,646		)	(1,622		)	(1,450		)
Prior service cost (credit) amortization	—			146			—			(453		)
Actuarial loss (gain) amortization	—			1,984			—			(402		)
	407			2,945			(820		)	21
Regulatory adjustment (2)	2,919			192			726			667
Net periodic benefit cost (credit)	$	3,326		$	3,137		$	(94	)	$	688

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Net Periodic Benefit Cost:
Service cost	$	2,358		$	998		$	2,805		$	411		$	881		$	2,641
Interest cost	4,728			2,095			7,576			1,276			1,254			4,338
Expected return on plan assets	(6,238		)	(2,461		)	(7,939		)	(3,380		)	(1,367		)	(4,349		)
Prior service cost (credit) amortization	—			133			440			—			(409		)	(1,359		)
Actuarial loss (gain) amortization	—			2,308			5,951			—			273			(1,208		)
Curtailment recognition (1)	—			—			—			(15,332		)	—			—
	848			3,073			8,833			(17,025		)	632			63
Regulatory adjustment (2)	5,892			253			575			1,464			657			1,999
Net periodic benefit cost (credit)	$	6,740		$	3,326		$	9,408		$	(15,561	)	$	1,289		$	2,062

⁽¹⁾  Subsequent to the Merger, the Company amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $74.6 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $59.3 million.  As such, the net curtailment gain recognition was $15.3 million.

⁽²⁾  In the Distribution segment, the Company recovers certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company is exposed to certain risks in its ongoing business operations.  The primary risks managed by using derivative instruments are interest rate risk and commodity price risk.  Interest rate swaps and treasury rate locks are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time.  Natural gas and NGL price swaps as well as call options and NGL processing spread swaps are the principal derivative instruments used by the Company 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.  

The Company recognizes all derivative instruments as assets or liabilities at fair value in the unaudited interim condensed consolidated balance sheets.

Interest Rate Contracts

The Company may enter into interest rate swaps to manage its exposure to changes in interest payments on long-term debt attributable to movements in market interest rates, and may enter into treasury rate locks to manage its exposure to changes in future interest payments attributable to changes in treasury rates prior to the issuance of new long-term debt instruments.

Interest Rate Swaps.  In 2011, the Company entered into interest rate swap agreements to hedge the $600 million Junior Subordinated Notes with an aggregate notional amount of $525 million, of which $450 million were for ten-year periods and $75 million were for five-year periods.  These interest rate swaps became effective on November 1, 2011.  The Company pays interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011.  The interest rate swaps effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notes and are accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  The floating rate LIBOR-based portion of the interest payments was exchanged for weighted average fixed rate interest payments of 3.63%.  In conjunction with the Merger, the Company discontinued hedge accounting treatment on these interest rate swaps.  Therefore, future changes in fair value will be recognized in earnings.

The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012.  These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified intointerest expense in the same periods during which the related interest payments on long-term debt impacted earnings.  These swaps terminated in the first quarter of 2012.

For the predecessor period in 2012 during which hedge accounting treatment was applied, there was no swap ineffectiveness.

Treasury Rate Locks.  As of September 30, 2012, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt.  During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

Commodity Contracts – Gathering and Processing Segment

The Company 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 natural gas and NGL volumes resulting from movements in market commodity prices.

Natural Gas Price Swaps.  As of September 30, 2012, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 2,760,000 MMBtu for the remainder of 2012 and 10,037,500 MMBtu for 2013.  These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of September 30, 2012, approximately $0.7 million of net after-tax losses in accumulated other comprehensive income related to these natural gas price swaps are expected to be recognized in operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Price Swaps.  As of September 30, 2012, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 16,449,048 gallons (2,319,300 MMBtu equivalent basis) for the remainder of 2012.  These NGL price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted NGL sales impact earnings.  As of September 30, 2012, approximately $6.1 million of net after-tax losses in accumulated other comprehensive income related to these NGL price swaps are expected to be recognized in operating revenues during the next 12 months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Commodity Contracts - Distribution Segment

The Company 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.

Natural Gas Price Swaps.  As of September 30, 2012, the Company had outstanding pay-fixed natural gas price swaps and call options with total notional amounts of 3,660,000 MMBtu, 12,130,000 MMBtu and 2,640,000 MMBtu for the remainder of 2012, 2013 and 2014, respectively.  These natural gas price swaps and call options are accounted for as economic hedges, with changes in their fair value recorded to deferred natural gas purchases.

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the unaudited interim condensed consolidated balance sheets at the dates indicated:

	Fair Value
	Asset Derivatives				Liability Derivatives
	Successor		Predecessor		Successor		Predecessor
Balance Sheet Location	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	—	$	19,936
Deferred credits	—		—		—		59,789
Commodity contracts — Gathering and Processing:
Natural gas price swaps
Prepayments and other assets	1,498		6,124		—		—
Accounts payable — related parties	—		—		7,135		—
NGL price swaps
Prepayments and other assets	4,323		—		—		1,996
Derivative instruments — liabilities	—		—		—		4,144
	$	5,821	$	6,124	$	7,135	$	85,865
Economic Hedges:
Interest rate contracts:
Derivative instruments — liabilities	$	—	$	—	$	17,310	$	—
Deferred credits	—		—		63,142		—
Commodity contracts — Gathering and Processing:
Other derivative instruments
Derivative instruments — liabilities	—		—		—		50
Commodity contracts — Distribution:
Natural gas price swaps
Other non-current assets	768		—		—		—
Derivative instruments — liabilities	—		—		7,958		34,468
Deferred credits	—		3		—		5,643
	$	768	$	3	$	88,410	$	40,161
Total	$	6,589	$	6,127	$	95,545	$	126,026

The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim condensed consolidated balance sheet on a net basis and disclosed herein on a gross basis.

The following tables summarize the location and amount (excluding income tax effects) of derivative instrument gains and losses reported in the Company’s unaudited interim condensed consolidated financial statements for the periods presented:

	Successor			Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	50,283
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			5,715
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in accumulated other comprehensive income	(5,526		)	8,434
Reclassification of unrealized gain from accumulated other comprehensive income - increase of operating revenues	6,011			5,598
Economic Hedges:
Interest rate contracts:
Change in fair value - increase ininterest expense	(4,294		)	—
Commodity contracts - Gathering and Processing:
Change in fair value of hedges - decrease in operating revenues	—			3,963
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in deferred natural gas purchases	(10,866		)	10,114

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
Cash Flow Hedges:
Interest rate contracts:
Change in fair value - increase in accumulated other comprehensive income	$	—		$	6,174		$	71,031
Reclassification of unrealized loss from accumulated other comprehensive income - increase of interest expense	—			8,085			16,881
Commodity contracts - Gathering and Processing:
Change in fair value - increase in accumulated other comprehensive income	5,851			4,619			7,420
Reclassification of unrealized gain from accumulated other comprehensive income	11,547			2,043			14,782
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	15,415			—			—
Commodity contracts - Gathering and Processing:
Change in fair value of other hedges - decrease in operating revenues	—			50			27,611
Commodity contracts - Distribution:
Change in fair value - decrease in deferred natural gas purchases	(30,961		)	(1,957		)	(13,658		)

Derivative Instrument Contingent Features

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

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Environmental Liabilities Table

The table below reflects the amount of accrued liabilities recorded in the condensed consolidated balance sheets at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  Except for matters discussed above, the Company does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Current	$	4,363	$	9,353
Noncurrent	24,588		11,635
Total environmental liabilities	$	28,951	$	20,988

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Fair Value Measurement (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012
Assets:
Commodity derivatives	$ 6,589
Total	6,589
Liabilities:
Commodity derivatives	15,093
Interest-rate swap derivatives	80,452
Total	95,545
Level 1 [Member]
Assets:
Commodity derivatives	0
Total	0
Liabilities:
Commodity derivatives	0
Interest-rate swap derivatives	0
Total	0
Level 2 [Member]
Assets:
Commodity derivatives	6,589
Total	6,589
Liabilities:
Commodity derivatives	15,093
Interest-rate swap derivatives	80,452
Total	95,545
Level 3 [Member]
Assets:
Commodity derivatives	0
Total	0
Liabilities:
Commodity derivatives	0
Interest-rate swap derivatives	0
Total	$ 0

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Business Combinations, Policy

Business Combination Accounting

The Company’s March 26, 2012 merger transaction with ETE was accounted for by ETE using business combination accounting.  Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value.  By the application of “push-down” accounting, Southern Union’s assets, liabilities and equity were accordingly adjusted to fair value on March 26, 2012.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  See Note 3 to our condensed consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.

Due to the application of “push-down” accounting, the Company’s financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting.  Periods prior to March 26, 2012 are identified herein as “Predecessor,” while periods subsequent to the ETE Merger are identified as “Successor.”

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ETE Merger and Holdco Transaction (Tables)

9 Months Ended

Sep. 30, 2012

Business Combinations [Abstract]

Business acquisition

The table below represents the allocation of the total consideration to Southern Union’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values.  Certain amounts included in the preliminary purchase price allocation as of September 30, 2012 have been changed from amounts previously reflected based on management's review of the valuation. Management is continuing to validate certain assumptions made in connection with the purchase price allocation.

Cash and cash equivalents	$	36,792
Other current assets	524,246
Property and equipment	6,958,768
Goodwill	2,030,271
Identified intangibles (1)	55,000
Other noncurrent assets	290,360
Long-term debt, including current portion	(3,333,706		)
Deferred income taxes	(1,698,352		)
Other liabilities	(950,513		)
Total purchase price	$	3,912,866

⁽¹⁾ Identified intangibles will be amortized over an estimated life of approximately 17.5 years and are included in deferred charges in the unaudited condensed consolidated balance sheet.

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Derivative Instrument and Hedging Activities 2 (Details) (USD $)	Sep. 30, 2012 Successor [Member]		Sep. 30, 2012 Successor [Member] Cash Flow Hedges: [Member]		Sep. 30, 2012 Successor [Member] Cash Flow Hedges: [Member] Interest rate contracts [Member] Derivative instruments - liabilities [Member]		Sep. 30, 2012 Successor [Member] Cash Flow Hedges: [Member] Interest rate contracts [Member] Deferred credits [Member]		Sep. 30, 2012 Successor [Member] Economic Hedges [Member]		Sep. 30, 2012 Successor [Member] Economic Hedges [Member] Interest rate contracts [Member] Derivative instruments - liabilities [Member]		Sep. 30, 2012 Successor [Member] Economic Hedges [Member] Interest rate contracts [Member] Deferred credits [Member]		Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Deferred credits [Member]	Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Prepayments and other assets [Member]		Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Accounts payable - related parties [Member]		Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] NGL price swaps [Member] Derivative instruments - liabilities [Member]		Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] NGL price swaps [Member] Prepayments and other assets [Member]		Sep. 30, 2012 Successor [Member] Gathering and Processing [Member] Economic Hedges [Member] Other derivative instruments [Member] Derivative instruments - liabilities [Member]		Sep. 30, 2012 Successor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Derivative instruments - liabilities [Member]		Sep. 30, 2012 Successor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Other Assets [Member]		Sep. 30, 2012 Successor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Deferred credits [Member]		Dec. 31, 2011 Predecessor [Member]		Dec. 31, 2011 Predecessor [Member] Cash Flow Hedges: [Member]		Dec. 31, 2011 Predecessor [Member] Cash Flow Hedges: [Member] Interest rate contracts [Member] Derivative instruments - liabilities [Member]		Dec. 31, 2011 Predecessor [Member] Cash Flow Hedges: [Member] Interest rate contracts [Member] Deferred credits [Member]		Dec. 31, 2011 Predecessor [Member] Economic Hedges [Member]		Dec. 31, 2011 Predecessor [Member] Economic Hedges [Member] Interest rate contracts [Member] Derivative instruments - liabilities [Member]		Dec. 31, 2011 Predecessor [Member] Economic Hedges [Member] Interest rate contracts [Member] Deferred credits [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Deferred credits [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Prepayments and other assets [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] Natural gas price swaps [Member] Accounts payable - related parties [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] NGL price swaps [Member] Derivative instruments - liabilities [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Cash Flow Hedges: [Member] NGL price swaps [Member] Prepayments and other assets [Member]		Dec. 31, 2011 Predecessor [Member] Gathering and Processing [Member] Economic Hedges [Member] Other derivative instruments [Member] Derivative instruments - liabilities [Member]		Dec. 31, 2011 Predecessor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Derivative instruments - liabilities [Member]		Dec. 31, 2011 Predecessor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Other Assets [Member]		Dec. 31, 2011 Predecessor [Member] Distribution [Member] Economic Hedges [Member] Natural gas price swaps [Member] Deferred credits [Member]
Derivative [Line Items]
Asset Derivatives	$ 6,589,000	[1]	$ 5,821,000	[1]	$ 0	[1]	$ 0	[1]	$ 768,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	$ 1,498,000	[1]	$ 0	[1]	$ 0	[1]	$ 4,323,000	[1]	$ 0	[1]	$ 0	[1]	$ 768,000	[1]	$ 0	[1]	$ 6,127,000	[1]	$ 6,124,000	[1]	$ 0	[1]	$ 0	[1]	$ 3,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 6,124,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 3,000	[1]
Liability Derivatives	$ 95,545,000	[1]	$ 7,135,000	[1]	$ 0	[1]	$ 0	[1]	$ 88,410,000	[1]	$ 17,310,000	[1]	$ 63,142,000	[1]	$ 0	$ 0	[1]	$ 7,135,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 7,958,000	[1]	$ 0	[1]	$ 0	[1]	$ 126,026,000	[1]	$ 85,865,000	[1]	$ 19,936,000	[1]	$ 59,789,000	[1]	$ 40,161,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 4,144,000	[1]	$ 1,996,000	[1]	$ 50,000	[1]	$ 34,468,000	[1]	$ 0	[1]	$ 5,643,000	[1]

[1] The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis. If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim condensed consolidated balance sheet on a net basis and disclosed herein on a gross basis.

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Comprehensive Income (Loss) 2 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012 Successor [Member]	Dec. 31, 2011 Predecessor [Member]
Comprehensive Income Loss [Line Items]
Interest rate hedges, net	$ 0	$ (50,259)
Commodity hedges, net	(3,643)	(11)
Benefit plans:
Net actuarial loss and prior service costs, net - pensions	0	(51,845)
Net actuarial gain and prior service credit, net - OPEB	0	(14,542)
Equity investments, net	(93)	(2,535)
Total accumulated other comprehensive income (loss), net of tax	$ (3,736)	$ (119,192)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2012 Successor [Member]	Sep. 30, 2012 Successor [Member]	Mar. 25, 2012 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]	Sep. 30, 2011 Predecessor [Member]
Net income (loss)	$ 16,986	$ (9,796)	$ 49,917	$ 58,032	$ 178,467
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	0	0	3,878	(31,586)	(44,577)
Reclassification of unrealized loss on interest rate hedges into earnings	0	0	4,946	3,421	10,106
Change in fair value of commodity hedges	(3,534)	3,743	2,954	5,395	4,746
Reclassification of unrealized gain on commodity hedges into earnings	(3,845)	(7,386)	(1,307)	(3,581)	(9,455)
Reclassificcation of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	0	0	1,815	709	2,116
Change in other comprehensive income from equity investments	(291)	(93)	29	35	107
Other comprehensive income (loss), net of tax	(7,670)	(3,736)	12,315	(25,607)	(36,957)
Comprehensive income (loss)	$ 9,316	$ (13,532)	$ 62,232	$ 32,425	$ 141,510

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ETE Merger and Holdco Transaction

9 Months Ended

Sep. 30, 2012

Business Combinations [Abstract]

ETE Merger and ETP Merger

ETE MERGER AND HOLDCO TRANSACTION:

Description of Merger

On March 26, 2012, the Company, ETE, and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub), completed their previously announced merger transaction.  Pursuant to the Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 (as amended, the Merger Agreement), among the Company, ETE and Merger Sub, Merger Sub was merged with and into the Company, with the Company continuing as the surviving corporation as an indirect, wholly-owned subsidiary of ETE (the Merger).  The Merger became effective on March 26, 2012 at 12:59 p.m., Eastern Time (the Effective Time).

At the Effective Time, each share of the Company’s common stock, par value $1.00 per share issued and outstanding (Southern Union Common Stock), immediately prior to the Effective Time (other than shares of Southern Union Common Stock held by stockholders properly exercising appraisal rights available under Section 262 of the Delaware General Corporation Law (DGCL) or shares of Southern Union Common Stock held directly or indirectly by the Company or any of its wholly-owned subsidiaries immediately prior to the Effective Time) was converted into the right to receive, as consideration for the Merger (the Merger Consideration), at the election of the holder of such share, either (i) $44.25 in cash (the Cash Consideration) or (ii) 1.00x ETE common unit (the Equity Consideration).

Under the terms of the Merger Agreement, Southern Union stockholders made an election to exchange each outstanding share of Southern Union Common Stock for $44.25 of cash or 1.00x ETE common unit, with no more than 60% of the aggregate

Merger Consideration payable in cash and no more than 50% of the aggregate Merger Consideration payable in ETE common units.  Based on the final election results, the Merger Consideration was paid as follows:

• Holders of approximately 54% of outstanding Southern Union Common Stock, or 67,985,929 Southern Union shares, elected and received cash.

• Holders of approximately 46% of outstanding Southern Union Common Stock, or 56,981,860 Southern Union shares, received ETE common units.  This amount is comprised of 38,872,598 Southern Union shares for which holders elected to receive ETE common units and 18,109,262 Southern Union shares for which holders either did not make an election (other than dissenting shares), did not deliver a valid election form prior to the election deadline or did not properly deliver shares of Southern Union Common Stock for which elections were made pursuant to the notice of guaranteed delivery procedure and, therefore, were deemed to have elected to receive ETE common units.

In connection with the consummation of the ETE Merger, on March 27, 2012, the New York Stock Exchange (NYSE) filed a notification of removal from listing with the SEC to delist the Southern Union Common Stock from the NYSE.  In addition, the Company filed with the SEC a certification and notice of termination requesting that the Southern Union Common Stock be deregistered under Section 12(b) of the Securities Exchange Act of 1934, as amended.

Pursuant to the Third Amended and Restated Company 2003 Stock and Incentive Plan (the Equity Plan), individual award agreements thereunder and the terms of the Merger Agreement, all awards of stock options and stock appreciation rights outstanding immediately, to the extent not already vested, became vested and exercisable prior to the Effective Time, in accordance with the terms of the Equity Plan.  All unexercised options and stock appreciation rights, including those for which vesting was accelerated, outstanding immediately prior to the Effective Time were cancelled and terminated at the Effective Time.  In consideration of such cancellation and termination, each stock option and stock appreciation right so cancelled and terminated was converted into the right to receive an amount in cash equal to $44.25 less (i) the applicable exercise price and (ii) any applicable deductions and withholdings required by law.

Additionally, shares of restricted stock for which restrictions have not otherwise lapsed or expired and were outstanding prior to the Effective Time had their associated restrictions automatically and without an action by the holder lapse/expire prior to the Effective Time, and each share of Southern Union Common Stock subject to such restricted stock grant was issued and converted into the right to receive Merger Consideration (in the form of Cash Consideration or Equity Consideration at the election of the holder of such restricted stock grant), less all deductions and withholdings required by law.  Each holder of the outstanding restricted stock grant made an election of Equity Consideration and the applicable deduction was made by reducing the number of ETE common units otherwise payable as part of the consideration for such restricted stock (with the ETE common units valued at the closing price of ETE on the day prior to the closing of the Merger for this purpose).

Restrictions on each awards of cash restricted stock units outstanding immediately prior to the Effective Time expired and each restricted stock unit was converted into the right to receive a lump sum cash payment equal to (i) $44.25 multiplied by the total number of shares of Southern Union Common Stock underlying such restricted stock units, less (ii) any applicable deductions and withholdings required by law.

The vesting of the equity-based awards, as described above, occurred as required under the change in control provisions of the Equity Plan.  The total remaining unrecognized compensation costs of $24.9 million associated with such vested awards was not recorded in either of the predecessor or successor periods reflected herein. The total of $136.8 million and 178,851 ETE Common Units issued to the holders of the awards in connection with the vesting was accounted for as consideration transferred in the Merger.

In connection with, and immediately prior to the Effective Time of the Merger, CrossCountry Energy, LLC, an indirect wholly-owned subsidiary of the Company (CrossCountry Energy), ETP, Citrus ETP Acquisition, L.L.C. (ETP Merger Sub), Citrus ETP Finance LLC, ETE, PEPL Holdings, LLC, a newly created indirect wholly-owned subsidiary of the Company (PEPL Holdings), and the Company consummated the transactions contemplated by that certain Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, as amended by Amendment No. 1 thereto dated as of September 14, 2011 and Amendment No. 2 thereto dated as of March 23, 2012 (as amended, the Citrus Merger Agreement) by and among ETP, ETP Merger Sub and Citrus ETP Finance LLC, on the one hand, and ETE, CrossCountry Energy, PEPL Holdings and the Company, on the other hand.

Immediately prior to the Effective Time, the Company, CrossCountry Energy and PEPL Holdings became parties to the Citrus Merger Agreement by joinder to, and the Company assumed the obligations and rights of ETE thereunder.  The Company made certain customary representations, warranties, covenants and indemnities in the Citrus Merger Agreement.  Pursuant to the Citrus Merger Agreement, ETP Merger Sub was merged with and into CrossCountry Energy (the Citrus Merger), with CrossCountry Energy continuing as the surviving entity in the Citrus Merger as a wholly-owned subsidiary of ETP and, as a result thereof, ETP, through its subsidiaries, indirectly owns 50% of the outstanding capital stock of Citrus.  As consideration for the Citrus Merger, Southern Union received from ETP $2.0 billion, consisting of approximately $1.9 billion in cash and $105 million of common units representing limited partner interests in ETP.

Immediately prior to the Effective Time, $1.45 billion of the total cash consideration received in respect of the Citrus Merger was contributed to Merger Sub in exchange for an equity interest in Merger Sub.  In connection with the Merger, at the Effective Time, such equity interest in Merger Sub held by CCE Holdings was cancelled and retired.

Pursuant to the Citrus Merger Agreement, immediately prior to the Effective Time, (i) the Company contributed its ownership interests in Panhandle Eastern Pipe Line Company, LP and Southern Union Panhandle, LLC (collectively, the Panhandle Interests) to PEPL Holdings (the Panhandle Contribution); and (ii) following the Panhandle Contribution, the Company entered into a contingent residual support agreement (the Support Agreement) with ETP and Citrus ETP Finance LLC, pursuant to which the Company agreed to provide contingent, residual support to Citrus ETP Finance LLC (on a non-recourse basis to the Company) with respect to Citrus ETP Finance LLC’s obligations to ETP to support the payment of $2.0 billion in principal amount of senior notes issued by ETP on January 17, 2012.

Expenses Related to the Merger

Merger-related expenses were $72.1 million and $18.7 million in the successor and predecessor periods in 2012, respectively.  Such expenses include legal and other outside service costs, charges resulting from employment agreements with certain executives that provided for compensation when their employment was terminated and severance costs associated with administrative headcount reductions. These expenses were included in Operating, maintenance, and general expenses in the unaudited condensed consolidated statement of operations.

Allocation of Consideration Transferred

The Merger was accounted for using business combination accounting under applicable accounting principles.  Business combination accounting 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. 

The table below represents the allocation of the total consideration to Southern Union’s tangible and intangible assets and liabilities as of March 26, 2012 based upon management’s estimate of their respective fair values.  Certain amounts included in the preliminary purchase price allocation as of September 30, 2012 have been changed from amounts previously reflected based on management's review of the valuation. Management is continuing to validate certain assumptions made in connection with the purchase price allocation.

Cash and cash equivalents	$	36,792
Other current assets	524,246
Property and equipment	6,958,768
Goodwill	2,030,271
Identified intangibles (1)	55,000
Other noncurrent assets	290,360
Long-term debt, including current portion	(3,333,706		)
Deferred income taxes	(1,698,352		)
Other liabilities	(950,513		)
Total purchase price	$	3,912,866

⁽¹⁾ Identified intangibles will be amortized over an estimated life of approximately 17.5 years and are included in deferred charges in the unaudited condensed consolidated balance sheet.

The goodwill resulting from the Merger was primarily due to expected commercial and operational synergies and is not deductible for tax purposes. Goodwill was allocated by reportable business segment as $1.17 billion to the Transportation and Storage segment; $598.3 million to the Gathering and Processing segment; $251.8 million to the Distribution segment; and $10.8 million to Corporate and Other.

Holdco Transaction

On October 5, 2012, ETE and ETP completed the Holdco Transaction, immediately following the closing of ETP's acquisition of Sunoco whereby, (i) ETE contributed its interest in Southern Union into an ETP-controlled entity, in exchange for a 60% equity interest in the new entity, Holdco, and (ii) ETP contributed its interest in Sunoco to Holdco and retained a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. This transaction did not result in a new basis of accounting for Southern Union.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Related Party Transactions [table text block]

The following table provides a summary of the related party balances included in our condensed consolidated balance sheets at the dates indicated:

	Successor		Predecessor
	September 30, 2012		December 31, 2011
Investment in ETP	$	100,182	$	—
Accounts receivable — affiliates (1)	14,004		10,467
Note payable — ETE (2)	166,217		—
Accounts payable — affiliates (3)	32,251		178

⁽¹⁾  Primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates.

⁽²⁾  See Note 6 for more information regarding the note payable to ETE.

⁽³⁾  Primarily related to various administrative and operating costs paid by affiliates on behalf of the Company

Related Party Transactions, Statement of Operations [Table Text Block]

The following table provides a summary of the related party activity included in our condensed consolidated statements of operations. Prior period amounts were not included as they were immaterial.

	Successor
	Three months ended September 30, 2012			Period from Acquisition (March 26, 2012) to September 30, 2012
Operating revenues — ETE	$	10,180		$	19,076
Cost of natural gas and other energy	4,688			13,170
Operating, maintenance and general	20,235			23,537
Interest expense	3,487			3,351
Losses from unconsolidated investments	(1,065		)	(381		)

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012 Successor [Member]		Dec. 31, 2011 Predecessor [Member]
Related Party Transactions [Line Items]
Investment in ETP	$ 100,182		$ 0
Accounts receivable - affiliates	14,004	[1]	10,467	[1]
Note payable - ETE	166,217	[2]	0	[2]
Accounts payable - affiliates	$ 32,251	[3]	$ 178	[3]

[1] Primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates.

[2] See Note 6 for more information regarding the note payable to ETE

[3] Primarily related to various administrative and operating costs paid by affiliates on behalf of the Company

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Regulation and Rates

9 Months Ended

Sep. 30, 2012

Regulation and Rates [Abstract]

Regulation and Rates

REGULATION AND RATES:

Panhandle.  In October 2011, Trunkline and Sea Robin jointly filed with FERC to transfer all of Trunkline's offshore facilities, and certain related onshore facilities, by sale and transfer to Sea Robin to consolidate and streamline the ownership and operation of all regulated offshore assets under one entity and better position the offshore assets competitively.  Several parties filed interventions and protests of this filing.  On June 21, 2012, FERC issued an order granting Trunkline permission and approval to proceed with the transfer, subject to compliance with certain regulatory requirements.  On July 31, 2012 Sea Robin and Trunkline made the necessary compliance filings with FERC.  The transfer of the offshore facilities to Sea Robin was completed in the third quarter of this year.

On July 26, 2012, Trunkline filed an application with the FERC for approval to transfer approximately 770 miles of underutilized loop piping facilities by sale to an affiliate. This sale is subject to FERC approval. These facilities would be converted to a crude oil transportation service. Several parties have intervened, commented, or protested this filing and the Company is currently responding to the Commission's requests for additional information on this application.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to 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.

Missouri Gas Energy.  On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million.  On February 10, 2010, the MPSC issued its Report and Order in this case, authorizing a revenue increase of $16.2 million and approving distribution rate structures for Missouri Gas Energy’s residential and small general service customers (which comprised approximately 99% of its total customers and approximately 91% of its net operating revenues at the time the rates went into effect) that eliminate the impact of weather and conservation for residential and small general service margin revenues and related earnings in Missouri.  The new rates became effective February 28, 2010.  Judicial review of the MPSC’s Report and Order is being sought by the Office of the Public Counsel, with respect to rate structure issues, and by Missouri Gas Energy, with respect to cost of capital issues.  By opinion issued on March 20, 2012, the Southern District of the Missouri Court of Appeals affirmed the MPSC’s Report and Order.  That opinion is now final.

New England Gas Company.  On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50% of the amount by which its 2007 earnings fell below a return on equity of 7%.  This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007.  On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments (ESA) in its entirety.  The Company appealed that decision to the Massachusetts Supreme Judicial Court (MSJC).  On November 13, 2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $1.7 million, representing 50% of the amount by which its 2008 earnings deficiency fell below a return on equity of 7%.  The MDPU held the 2008 ESA matter in abeyance pending judicial resolution of the issues pertaining to the 2007 ESA.  On February 11, 2011, the MSJC issued an opinion reversing the MDPU’s rejection of New England Gas Company’s 2007 ESA and remanded the matter back to the MDPU to determine the appropriate amount of the 2007 ESA and the method for recovery.  On July 13, 2011, New England Gas Company filed its motion for proceeding on remand requesting that the MDPU (i) find that $4.1 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a twelve month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $1.7 million over a twelve-month period beginning November 1, 2012.  On January 27, 2012, the MDPU issued its order approving the 2007 ESA in its entirety and authorizing recovery of approximately $4 million over a twelve-month period beginning February 1, 2012.  The 2008 ESA is awaiting further action by the MDPU.