UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~March~~June 3130, 2013



¨	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	~~75-0571592~~	75-0571592
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
(State or other jurisdiction ofincorporation or organization)		(I.R.S. EmployerIdentification No.)

3738 Oak Lawn Avenue	75219
Dallas, Texas	(Zip Code)
(Address of principal executive offices)

3738 Oak Lawn Avenue, Dallas, Texas 75219

~~Registrant’s~~(Address ~~telephone~~of ~~number,~~principal ~~including~~executive ~~area~~offices) ~~code:~~ (~~214)~~zip ~~981-0700~~code)

~~Indicate by check mark whether the registrant~~ (1214) 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.981-0700

~~Yes x No~~(Registrant’s ¨telephone number, including area code)

Indicate by check mark whether the registrant (1) has ~~submitted~~filed ~~electronically~~all ~~and~~reports ~~posted on its corporate Web site, if any, every Interactive Data File~~ required to be ~~submitted~~filed ~~and~~by ~~posted~~Section ~~pursuant~~13 toor ~~Rule~~15(d) ~~405~~ of ~~Regulation~~the ~~S-T~~Securities ~~(§232.405~~Exchange Act of ~~this~~1934 ~~chapter)~~ during the preceding 12 months (or for such shorter period that the registrant was required to ~~submit~~file such reports), and ~~post~~(2) has been subject to such ~~files)~~filing requirements for the past 90 days. Yes x No ¨

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x 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.

Table of Contents

FORM 10-Q

SOUTHERN UNION COMPANY

TABLE OF CONTENTS

		PAGE
PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income (Loss)	45
	Condensed Consolidated Statement of Stockholder’s Equity	56
	Condensed Consolidated Statements of Cash Flows	67
	Notes to Condensed Consolidated Financial Statements	78
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2224
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	2932
ITEM 4.	CONTROLS AND PROCEDURES	2933
PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	2933
ITEM 1A.	RISK FACTORS	2933
ITEM 6.	EXHIBITS	3034
SIGNATURE		3135

Table of Contents

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 the Company’s 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,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “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, projected, forecasted, estimated or expressed 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, 2012 filed with the Securities and Exchange Commission on March 1, 2013.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:

/d		per day
APUC		Algonquin Power & Utilities Corp
Btu		British thermal units
Citrus		Citrus Corp.
Citrus Merger		ETP’s acquisition of Citrus Corp. on March 26, 2012
EBITDA		Earnings before interest, taxes, depreciation and amortization
EPA		United States Environmental Protection Agency
ETE		Energy Transfer Equity, L.P.
ETE Merger		ETE’s acquisition of Southern Union on March 26, 2012
ETP		Energy Transfer Partners, L.P., a subsidiary of ETE
ETP GP		Energy Transfer Partners GP, L.P., the general partner of ETP
ETP LLC		Energy Transfer Partners, L.L.C., the general partner of ETP GP
Exchange Act		Securities Exchange Act of 1934
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
Holdco		ETP Holdco Corporation
KDHE		Kansas Department of Health and Environment
IDRs		Incentive Distribution Rights
LIBOR		London Interbank Offer Rate
Laclede Massachusetts		Plaza Massachusetts Acquisition, Inc.
Laclede Missouri		Plaza Missouri Acquisition, Inc.
LDC Disposal Group		Southern Union’s Missouri Gas Energy and New England Gas Company divisions
LNG		Liquefied natural gas
LNG Holdings		Trunkline LNG Holdings, LLC
MDPU		Massachusetts Department of Public Utilities
Merger Sub		Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE

Table of Contents

MGP Manufactured gas plant MMBtu Million British thermal units MMcf Million cubic feet NGL Natural gas liquids ~~NMED New Mexico Environment Department~~ NYMEX New York Mercantile Exchange OPEB plans Other postretirement employee benefit plans Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries PCB Polychlorinated biphenyl PEPL Panhandle Eastern Pipe Line Company, LP PEPL Holdings PEPL Holdings, LLC ppb parts per billion Regency Regency Energy Partners LP Sea Robin Sea Robin Pipeline Company, LLC SEC United States Securities and Exchange Commission SUGS Southern Union Gas Services Sunoco Sunoco, Inc. TBtu Trillion British thermal units ~~TCEQ Texas Commission on Environmental Quality~~ Trunkline Trunkline Gas 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, 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 reflects amounts for unconsolidated affiliates based on the Company's proportionate ownership.

iii

Table of Contents

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

The Company’s March 26, 2012 merger transaction with ETE (the “ETE Merger”) 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.

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.”

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2013			December 31, 2012
	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	~~165~~152		$	49
Accounts receivable, net	~~151~~69			155
Accounts receivable from related companies	80102			72
Inventories	~~169~~138			163
Exchanges receivable	259			11
Current assets held for sale	~~136~~102			184
Prepayments and other assets	~~149~~138			120
Total current assets	~~875~~710			754
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	54,~~616~~166			5,491
Construction work in progress	~~226~~47			272
	5,842			5,763
	4,213			5,763
Accumulated depreciation and amortization	(~~165~~140		)	(105		)
Net property, plant and equipment	54,~~677~~073			5,658
NON-CURRENT ASSETS HELD FOR SALE	~~992~~1,000			985
DEFERRED CHARGES	6963			65
UNCONSOLIDATED INVESTMENTS	~~114~~1,557			115
GOODWILL	2,~~364~~025			2,364
OTHER NON-CURRENT ASSETS	5560			52
Total assets	$	109,~~146~~488		$	9,993

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2013			December 31, 2012
	June 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long–term debt	$	~~256~~253		$	259
Accounts payable and accrued liabilities	~~197~~34			118
Accounts payable to related companies	~~148~~147			110
Federal, state and local taxes payable	20			16
Accrued interest	4117			32
Exchanges payable	~~146~~123			133
Derivative instruments	18			18
Current liabilities held for sale	8075			85
Other	4035			108
Total current liabilities	~~946~~722			879
LONG-TERM DEBT, less current maturities	31,~~048~~713			3,024
DEFERRED CREDITS	335			330
NOTE PAYABLE TO RELATED PARTY	1,090			—
DEFERRED INCOME TAXES	1,641			1,590
DEFERRED CREDITS	289			330
NON-CURRENT LIABILITIES HELD FOR SALE	142			142
DEFERRED INCOME TAXES	1,839			1,590
COMMITMENTS AND CONTINGENCIES (Note 11)
NON-CURRENT LIABILITIES HELD FOR SALE	140			142
COMMITMENTS AND CONTINGENCIES (Note 10)
STOCKHOLDER’S EQUITY:
Premium on capital stock	43,~~079~~947			4,079
Accumulated other comprehensive loss	(2520		)	(25		)
Accumulated deficit	(20232		)	(26		)
Total stockholder’s equity	43,~~034~~695			4,028
Total liabilities and stockholder’s equity	$	109,~~146~~488		$	9,993

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

(unaudited)

	Successor						Predecessor
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
OPERATING REVENUES	$	316		$	387
OPERATING REVENUES	$	393		$	31		$	443
OPERATING EXPENSES:
OPERATING EXPENSES:
Cost of natural gas and other energy	66			151
Cost of natural gas and other energy	159			14			197
Operating, maintenance and general	88			105
Operating, maintenance and general	120			61			116
Depreciation and amortization	47			66
Depreciation and amortization	59			4			49
Total operating expenses	201			322
Total operating expenses	338			79			362
OPERATING INCOME	115			65
OPERATING INCOME (LOSS)	55			(48		)	81
OTHER INCOME (EXPENSE):
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(12		)	(57		)
Interest expense, net of interest capitalized	(33		)	(4		)	(50		)
Earnings from unconsolidated investments	5			1
Earnings from unconsolidated investments	1			—			16
Other, net	(2		)	1
Other, net	1			—			(2		)
Total other expenses, net	(9		)	(55		)
Total other expenses, net	(31		)	(4		)	(36		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	106			10
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	24			(52		)	45
Income tax expense from continuing operations	75			6
Income tax expense (benefit) from continuing operations	10			(12		)	12
INCOME FROM CONTINUING OPERATIONS	31			4
INCOME (LOSS) FROM CONTINUING OPERATIONS	14			(40		)	33
Income from discontinued operations	9			8
Income from discontinued operations	22			1			17
NET INCOME	$	40		$	12
NET INCOME (LOSS)	$	36		$	(39	)	$	50

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

~~CONSENSED~~CONDENSED CONSOLIDATED STATEMENTS OF ~~COMPREHENSIVE INCOME (LOSS)~~OPERATIONS

(Dollars in millions)

(unaudited)

	Successor						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
	Six Months EndedJune 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Net income (loss)	$	36		$	(39	)	$	50
OPERATING REVENUES	$	709		$	418		$	443
Other comprehensive income, net of tax:
OPERATING EXPENSES:
Change in fair value of interest rate hedges	—			—			4
Cost of natural gas and other energy	225			165			197
Reclassification of unrealized loss on interest rate hedges into earnings	—			—			5
Operating, maintenance and general	208			166			116
Change in fair value of commodity hedges	—			1			3
Depreciation and amortization	106			70			49
Reclassification of unrealized (gain) loss on commodity hedges into earnings	—			—			(1		)
Total operating expenses	539			401			362
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			—			1
OPERATING INCOME	170			17			81
	—			1			12
OTHER INCOME (EXPENSE):
Comprehensive income (loss)	$	36		$	(38	)	$	62
Interest expense, net of interest capitalized	(45		)	(61		)	(50		)
Earnings from unconsolidated investments	6			1			16
Other, net	(1		)	1			(2		)
Total other expenses, net	(40		)	(59		)	(36		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	130			(42		)	45
Income tax expense (benefit) from continuing operations	85			(6		)	12
INCOME (LOSS) FROM CONTINUING OPERATIONS	45			(36		)	33
Income from discontinued operations	31			9			17
NET INCOME (LOSS)	$	76		$	(27	)	$	50

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

~~CONDENSED~~CONSENSED CONSOLIDATED ~~STATEMENT~~STATEMENTS OF ~~STOCKHOLDER’S~~COMPREHENSIVE ~~EQUITY~~INCOME (LOSS)

(Dollars in millions)

(unaudited)

	Premium on Capital Stock			Accumulated Other Comprehensive Loss			Accumulated Deficit			TotalStockholder’sEquity
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012
Balance, December 31, 2012	$	4,079		$	(25	)	$	(26	)	$	4,028
Net income	$	40		$	12
Unit-based compensation	1			—			—			1
Other comprehensive income, net of tax:
Dividends paid on common stock	—			—			(30		)	(30		)
Change in fair value of commodity hedges	(3		)	6
Net income	—			—			36			36
Reclassification of unrealized gain on commodity hedges into earnings	—			(3		)
Other	(1		)	—			—			(1		)
Actuarial gain relating to pension and other postretirement benefits	2			—
Balance, March 31, 2013	$	4,079		$	(25	)	$	(20	)	$	4,034
	(1		)	3
Comprehensive income	$	39		$	15

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



	Successor						Predecessor
	Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Net income (loss)	$	76		$	(27	)	$	50
Other comprehensive income, net of tax:
Change in fair value of interest rate hedges	—			—			4
Reclassification of unrealized loss on interest rate hedges into earnings	—			—			5
Change in fair value of commodity hedges	(3		)	7			3
Reclassification of unrealized gain on commodity hedges into earnings	—			(3		)	(1		)
Actuarial gain relating to pension and other postretirement benefits	2			—			1
	(1		)	4			12
Comprehensive income (loss)	$	75		$	(23	)	$	62

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED ~~STATEMENTS~~STATEMENT OF ~~CASH~~STOCKHOLDER’S ~~FLOWS~~EQUITY

(Dollars in millions)

(unaudited)

	Successor							Predecessor
	Premium on Capital Stock			Accumulated Other Comprehensive Loss			Accumulated Deficit				TotalStockholder’sEquity
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
Balance, December 31, 2012	$	4,079		$	(25	)	$	(26	)		$	4,028
CASH FLOWS FROM OPERATING ACTIVITES:
Other comprehensive income, net of tax	—			(1		)	—				(1		)
Net income (loss)	$	36		$	(39	)		$	50
Unit-based compensation	1			—			—				1
Reconciliation of net income to net cash provided by (used in) operating activities:
Dividends paid	—			—			(282		)		(282		)
Depreciation and amortization (including discontinued operations)	59			5				57
Net income	—			—			76				76
Deferred income taxes	22			(12		)		23
SUGS Contribution	(133		)	6			—				(127		)
Provision for bad debts	1			—				1
Balance, June 30, 2013	$	3,947		$	(20	)	$	(232	)		$	3,695
Amortization of costs charged to interest	(8		)	—				1
Net gain on curtailment of OPEB plans	—			(15		)		—
Unrealized gain on derivatives	(5		)	—				—
Non-cash compensation expense	2			—				2
Earnings from unconsolidated investments, net of cash distributions	—			—				(16		)
Changes in operating assets and liabilities, net of merger impact	131			(133		)		79
Net cash flows provided by (used in) operating activities	238			(194		)		197
CASH FLOWS FROM INVESTING ACTIVITES:
Additions to property, plant and equipment	(123		)	(2		)		(60		)
Loan repayment from unconsolidated investments	—			—				37
Distributions from unconsolidated affiliates in excess of cumulative earnings	1			—				—
Proceeds from Citrus Merger	—			—				1,895
Plant retirements and other	(1		)	—				(2		)
Net cash flows provided by (used in) investing activities	(123		)	(2		)		1,870
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			—				455
Dividends paid on common stock	(30		)	—				(19		)
Note payable - related party	—			221				—
Repayment of long-term debt	—			—				(1,048		)
Net change in revolving credit facilities	30			(47		)		12
Purchase of treasury stock	—			—				(1,453		)
Other	1			(2		)		(1		)
Net cash flows provided by (used in) financing activities	1			172				(2,054		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	116			(24		)		13
CASH AND CASH EQUIVALENTS, beginning of period	49			37				24
CASH AND CASH EQUIVALENTS, end of period	$	165		$	13			$	37

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Successor						Predecessor
	Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
CASH FLOWS FROM OPERATING ACTIVITES:
Net income (loss)	$	76		$	(27	)	$	50
Reconciliation of net income to net cash provided by (used in) operating activities:
Depreciation and amortization	106			79			57
Deferred income taxes	109			(2		)	23
Provision for bad debts	5			4			1
Amortization of costs charged to interest	(17		)	(9		)	1
Net gain on curtailment of OPEB plans	—			(15		)	—
Unrealized loss (gain) on derivatives	(28		)	20			—
Non-cash compensation expense	4			—			2
Earnings from unconsolidated investments, net of cash distributions	1			2			(16		)
Other	3			—			—
Changes in operating assets and liabilities, net of merger and contribution impact	33			(181		)	79
Net cash flows provided by (used in) operating activities	292			(129		)	197
CASH FLOWS FROM INVESTING ACTIVITES:
Proceeds from SUGS Contribution	463			—			—
Additions to property, plant and equipment	(166		)	(82		)	(60		)
Loan repayment from unconsolidated investments	—			—			37
Distributions from unconsolidated affiliates in excess of cumulative earnings	13			—			—
Proceeds from Citrus Merger	—			—			1,895
Plant retirements and other	—			(2		)	(2		)
Net cash flows provided by (used in) investing activities	310			(84		)	1,870
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt	—			—			455
Dividends paid	(282		)	—			(19		)
Note payable - related party	—			221			—
Payments on note payable - related party	—			(55		)	—
Repayment of long-term debt	—			—			(1,048		)
Net change in revolving credit facilities	(210		)	23			12
Purchase of treasury stock	—			—			(1,453		)
Other	(7		)	(2		)	(1		)
Net cash flows provided by (used in) financing activities	(499		)	187			(2,054		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	103			(26		)	13
CASH AND CASH EQUIVALENTS, beginning of period	49			37			24
CASH AND CASH EQUIVALENTS, end of period	$	152		$	11		$	37

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

(unaudited)


1.	DESCRIPTION OF BUSINESS:

~~Southern~~Business 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: Operations

•Southern ~~Transportation~~Union ~~and~~Company ~~Storage~~(“we”, —“us”, ~~The~~the ~~Transportation~~“Company” and ~~Storage~~“Southern ~~segment~~Union”) isowns ~~primarily~~and ~~engaged~~operates assets in the ~~interstate~~regulated ~~transportation~~ and ~~storage~~unregulated of natural gas, industry and ~~also~~is ~~provides~~primarily ~~LNG~~engaged ~~terminalling~~in ~~and~~the ~~regasification~~transportation, ~~services.~~storage ~~Its~~and ~~operations~~distribution ~~expand~~of ~~from~~natural gas in the ~~Gulf~~United ~~Coast~~States. The ~~region~~Company ~~throughout~~operates ~~the~~in ~~Midwest~~three ~~and~~reportable ~~Great~~segments ~~Lakes~~as ~~region.~~follows:

• ~~Gathering~~Transportation and ~~Processing~~Storage — The ~~Gathering~~Transportation and ~~Processing~~Storage segment is primarily engaged in ~~connecting~~the ~~wells~~interstate oftransportation ~~natural~~and ~~gas~~storage ~~producers~~of ~~to its gathering system, treating~~ natural gas ~~to remove impurities to meet pipeline quality specifications~~, ~~processing~~and ~~natural~~also ~~gas~~provides ~~for~~LNG ~~the~~terminalling ~~removal of NGL,~~ and ~~redelivering~~regasification ~~natural gas and NGL to a variety of markets~~services. Its operations ~~are~~extend ~~conducted~~from ~~through~~the ~~SUGS.~~Gulf AsCoast ~~discussed~~region inthroughout ~~Note~~the 3,Midwest ~~Southern Union completed its contribution of SUGS~~ and ~~its~~Great ~~parent~~Lakes ~~company to Regency for approximately $1~~region.~~50 billion consisting of cash, Regency common units and Regency Class F units on April 30, 2013.~~

• ~~Distribution~~Gathering ~~— The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri~~ and ~~Massachusetts.~~Processing ~~Through~~— ~~Southern~~On ~~Union’s~~April ~~regulated utility operations~~30, ~~Missouri Gas Energy and New England Gas Company~~2013, the Company ~~serves~~contributed ~~natural~~SUGS ~~gas end-user customers in Missouri~~ and ~~Massachusetts,~~its ~~respectively.~~parent Ascompany ~~discussed in Note 3, Southern Union and The Laclede Group, Inc. have entered into definitive purchase and sale agreements pursuant~~ to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division for approximately $1Regency.04 ~~billion,~~See ~~subject~~Note ~~to customary closing adjustments~~2. On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with APUC that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals. It is expected that the transactions contemplated by the purchase and sale agreements will close in the third quarter of 2013.

~~See~~• Distribution — The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. Through Southern Union’s regulated utility operations, Missouri Gas Energy and New England Gas Company, the Company serves natural gas end-user customers in Missouri and Massachusetts, respectively. As discussed in Note 32, ~~for~~Southern ~~information~~Union ~~related~~and The Laclede Group, Inc. have entered into definitive purchase and sale agreements pursuant to which Laclede Missouri has agreed to acquire the ~~Company~~assets of Southern Union’s ~~disposal~~Missouri Gas Energy division, and ~~other~~Laclede ~~related~~Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division for approximately $1.04 billion, subject to customary closing adjustments. In February 2013, The Laclede Group, Inc. entered into an agreement with APUC that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals. The transactions contemplated by the purchase and sale agreements are expected to close during the third and fourth quarters of 2013.

See Note 2. ~~SUMMARY~~for OFinformation ~~SIGNIFICANT~~related ~~ACCOUNTING~~to ~~POLICIES~~the ~~AND~~Company’s ~~OTHER~~disposal ~~MATTERS:~~and other related transactions.

There have been no changes in the Company’s significant accounting policies as disclosed in its Annual Report on Form 10-K for the year ended December 31, 2012.

3. DISPOSAL AND RELATED TRANSACTIONS:

SUGS Contribution

On April 30, 2013, the Company completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration to the Company was reduced by $107 million in estimated closing adjustments. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the Contribution Agreement. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency received as consideration.

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Holdco Transaction

On April 30, 2013, ETP acquired ~~from~~ ETE’s ~~its~~60% interest in Holdco ~~for approximately 49.5 million of newly issued ETP common units and $1.40 billion in cash~~, ~~less $68 million in estimated closing adjustments. Holdco is~~ the entity formed by ETP and ETE in 2012 to own the equity interests in Southern Union and Sunoco. As a result of this transaction, ETP now owns 100% of Holdco. ETP controlled Holdco prior to this transaction; therefore, the transaction did not constitute a change of control.

Preparation of Interim Financial Statements

The accompanying condensed consolidated balance sheet as of December 31, 2012, which has been derived from audited financial statements, and the unaudited interim condensed consolidated financial statements and notes thereto of the Company as of June 30, 2013 and for the three and six month periods ended June 30, 2013 and 2012, have been prepared in accordance with GAAP for interim condensed consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Company’s operations.

The accompanying unaudited interim condensed consolidated financial statements reflect adjustments that are, in the opinion of management, necessary for a fair statement of results for the interim period. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Southern Union Company presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, as filed with the SEC on March 1, 2013.

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2.	DISPOSAL AND RELATED TRANSACTIONS:

SUGS Contribution

On April 30, 2013, the Company completed its contribution to Regency of all of the membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $463 million in cash to the Company, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. The Company used a portion of the cash consideration to pay down $240 million in outstanding borrowings on the Southern Union Credit Facility. In addition, PEPL Holdings, a wholly-owned subsidiary of the Company, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution, as further discussed in Note 10. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.

Discontinued Operations

In December 2012, the Company entered into a purchase and sale agreement with The Laclede Group, Inc. pursuant to which Laclede Missouri has agreed to acquire the assets of the Missouri Gas Energy division and Laclede Massachusetts has agreed to acquire the assets of the New England Gas Company division (together, the “LDC Disposal Group”) for approximately $1.04 billion, subject to customary closing adjustments. OnIn February ~~11,~~ 2013, The Laclede Group, Inc. ~~announced that it had~~ entered into an agreement with APUC that will allow a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of New England Gas Company, subject to certain approvals. ItThe sale of Missouri Gas Energy is expected ~~that~~to ~~the~~close ~~transactions~~on ~~contemplated~~or byafter ~~the~~September ~~purchase~~1, 2013, and the sale ~~agreements~~of ~~will~~New England Gas Company is expected to close in the ~~third~~fourth quarter of 2013. All periods reflected herein have been restated to present the LDC Disposal Group’s operations as discontinued operations in the condensed consolidated statements of operations. The LDC Disposal Group’s assets and liabilities have been reported as assets and liabilities held for sale as of ~~March~~June 3130, 2013 and December 31, 2012.

Summarized financial information for Southern Union’s LDC Disposal Group is as follows:

	Successor					~~Predecessor~~				Predecessor
	Three Months EndedMarch 31, 2013		Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
	Three Months EndedJune 30,				Six Months EndedJune 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012		Period from January 1, 2012 to March 25, 2012
Revenue from discontinued operations	$	246	$	8		$	190
	2013		2012
Net income of discontinued operations, excluding effect of taxes and overhead allocations	56		1			27
Revenue from discontinued operations	$	111	$	87	$	357		$	95	$	190
Net income of discontinued operations, excluding effect of taxes and overhead allocations	42		13		98			14		27

The goodwill allocated to the LDC Disposal Group was $133 million at ~~March~~June 3130, 2013.

~~4. RELATED PARTY TRANSACTIONS:~~9

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3.	RELATED PARTY TRANSACTIONS:

Accounts receivable from related companies reflected on the condensed consolidated balance sheets primarily related to payroll funding and various administrative and operating costs paid by the Company on behalf of affiliates. Accounts payable from related companies 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~~ Predecessor period amounts were not included as they were immaterial.

	Three Months Ended March 31, 2013
	Three Months EndedJune 30,				Six Months EndedJune 30, 2013		Period from Acquisition (March 26, 2012) to June 30, 2012
Operating revenues — ETP	$	20
	2013		2012
Cost of natural gas and other energy	13
Operating revenues — ETP	$	9	$	7	$	29	$	7
Operating, maintenance and general	25
Cost of natural gas and other energy	3		6		16		6
Earnings from unconsolidated investments	1
Operating, maintenance and general	18		4		43		4
Interest expense	1		2		1		2
Earnings from unconsolidated investments	5		1		6		1

The Company received $2 million and $14 million in distributions related to its ~~investment~~investments in ETP and Regency, respectively, during the ~~three~~six months ended ~~March~~June 3130, 2013.

84. ACCUMULATED OTHER COMPREHENSIVE LOSS:

The table below presents the components in accumulated other comprehensive loss, net of tax:



	June 30, 2013			December 31, 2012
Commodity hedges	$	—		$	(3	)
Benefit plans:
Net actuarial loss and prior service costs — pensions	(9		)	(11		)
Net actuarial gain and prior service credit — OPEB plans	(11		)	(11		)
Total accumulated other comprehensive loss, net of tax	$	(20	)	$	(25	)

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5. ~~ACCUMULATED~~DEBT ~~OTHER COMPREHENSIVE LOSS~~OBLIGATIONS:

~~The~~Based ~~table~~on ~~below~~the ~~presents~~estimated borrowing rates currently available to the ~~components~~Company inand ~~accumulated~~its ~~other~~subsidiaries ~~comprehensive~~for ~~loss~~loans with similar terms and average maturities, ~~net~~the aggregate fair value of ~~tax~~the Company’s consolidated debt obligations at June 30, as2013 and December 31, 2012 was $3.10 billion and $3.39 billion, respectively. As of June 30, 2013 and December 31, 2012, the ~~dates~~aggregate ~~indicated:~~carrying amount of the Company’s consolidated debt obligations was $3.06 billion and $3.28 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.

	March 31, 2013			December 31, 2012
Commodity hedges	$	(3	)	$	(3	)
Benefit plans:
Net actuarial loss and prior service costs — pensions	(11		)	(11		)
Net actuarial gain and prior service credit — OPEB plans	(11		)	(11		)
Total accumulated other comprehensive loss, net of tax	$	(25	)	$	(25	)

Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of the Company’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% ~~DEBT~~Senior ~~OBLIGATIONS:~~Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, the Company entered into intercompany notes payable to ETP, which provide for the reimbursement by the Company of ETP’s payments under the newly issued notes.

~~Based~~Credit 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 March 31, 2013 and December 31, 2012 was $3.43 billion and $3.39 billion, respectively. As of March 31, 2013 and December 31, 2012, the aggregate carrying amount of the Company’s consolidated debt obligations was $3.30 billion and $3.28 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.Facilities

~~Credit~~Proceeds ~~Facilities. The~~from ~~Eighth Amended and Restated Revolving Credit Agreement (~~the ~~“Southern~~SUGS ~~Union~~Contribution ~~Credit~~were ~~Facility”)~~used ~~provides for borrowings of up~~ to repay $~~700~~240 million ~~and~~of ~~expires~~borrowings ~~in May 2016. Borrowings~~ under the ~~Southern~~Eighth ~~Union~~Amended ~~Credit Facility are available for working capital, other general company purposes~~ and ~~letter~~Restated ofRevolving ~~credit~~Credit ~~requirements. The~~Agreement ~~interest rate and commitment fee under~~ (the “Southern Union Credit Facility”) ~~are~~and ~~calculated using a pricing grid, which is based on~~ the ~~credit~~facility ~~ratings for Southern Union's senior unsecured notes. The annualized interest rate for the Southern Union Credit Facility~~ was 1terminated.~~83% as of March~~ ~~31, 2013.~~

AsPanhandle ofTerm ~~March 31, 2013 and December 31, 2012, the Company had $240 million and $210 million, respectively, outstanding under the Southern Union Credit Facility.~~Loans

InThe ~~connection~~effective ~~with~~interest rate for the ~~SUGS~~$455 ~~Contribution,~~million ~~borrowings~~LNG ~~under~~Holdings ~~the~~term ~~Southern~~loan ~~Union~~due ~~Credit~~February ~~Facility~~2015 ~~were~~was ~~repaid~~1.82% ~~and~~as ~~the~~of ~~facility~~June 30, ~~terminated~~2013.

~~Panhandle~~Covenants ~~Term~~Related ~~Loans. The~~to ~~effective~~Our ~~interest~~Credit ~~rate for the $455 million LNG Holdings term loan due February 2015 was 1.83% as of March 31, 2013.~~Agreements

~~Covenants Related to Our Credit Agreements.~~ We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of ~~March~~June 3130, 2013.

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76. RETIREMENT BENEFITS:

Components of Net Periodic Benefit Cost

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

	Pension Benefits						Other Postretirement Benefits
	Successor							Predecessor
	Three MonthsEndedJune 30, 2013			Three Months EndedJune 30, 2012			Three Months EndedJune 30, 2013				Three Months EndedJune 30, 2012
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
Net Periodic Benefit Cost:
Net Periodic Benefit Cost:
Service cost	$	2		$	2		$	1			$	—
Service cost	$	1		$	—			$	1
Interest cost	2			(1		)	—				1
Interest cost	2			—				2
Expected return on plan assets	(3		)	(1		)	(1		)		(2		)
Expected return on plan assets	(3		)	—				(2		)
	1			—			—				(1		)
Actuarial loss amortization	1			—				2
Regulatory adjustment (2)	2			—			(3		)		1
	1			—				3
Net periodic benefit cost	$	3		$	—		$	(3	)		$	—
Regulatory adjustment (2)	2			—				—
Net periodic benefit cost	$	3		$	—			$	3

	Other Postretirement Benefits
	Pension Benefits									Other Postretirement Benefits
	Successor						Predecessor			Successor						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
	Six Months EndedJune 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six Months EndedJune 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Net Periodic Benefit Cost:
Service cost	$	—3		$	—2		$	1		$	1		$	—		$	1
Interest cost	14			—(1		)	12			1			1			1
Expected return on plan assets	(26		)	—(1		)	(12		)	(3		)	(2		)	(1		)
Prior service credit amortization	—			—			(1—		)	—			—			(1		)
Curtailment recognition (1)	—			(15		)	—
Actuarial gain amortization	1			—			2			—			—			—
	(1		)	(15		)	—
Curtailment recognition (1)	—			—			—			—			(15		)	—
Regulatory adjustment (2)	3			—			1
	2			—			3			(1		)	(16		)	—
Net periodic benefit cost (credit)	$	2		$	(15	)	$	1
Regulatory adjustment (2)	4			—			—			—			1			1
Net periodic benefit cost (credit)	$	6		$	—		$	3		$	(1	)	$	(15	)	$	1

⁽¹⁾

Subsequent to the ETE Merger, the Company amended certain of its OPEB 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 $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

⁽²⁾

In 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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87. TAXES ON INCOME:

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

	Successor							~~Predecessor~~						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012			Six Months EndedJune 30, 2013				Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Total income tax expense (benefit) from continuing operations	$	10		$	(12	)		$	12
Income tax expense (benefit)	$	75		$	6		$	85			$	(6	)	$	12
Effective tax rate	4171		%	2360		%	65	27	%	%	14		%	27		%

The Company’s effective income tax rate for the ~~period~~three and six months ended ~~March~~June 3130, 2013 was higher than the ~~U.S.~~ federal ~~income tax~~ statutory rate of 35% primarily due to state income taxes resulting from the SUGS Contribution and other internal restructuring activities. ~~During~~ The effective income tax rate for the period from March 26, 2012 to ~~March~~June 3130, 2012, ~~the Company’s effective income tax rate~~ was lower than the federal statutory rate primarily due to the Company’s pre-tax loss as a result of merger-related expenses coupled with non-deductible executive compensation included in the merger-related expenses. The ~~During~~effective income tax rate for the period from January 1, 2012 to March 25, 2012, ~~the effective income tax rate~~ was lower than the federal statutory rate primarily asdue ato ~~result of~~ the dividend received ~~deduction~~reduction for the anticipated receipt of dividends associated with the earnings from the Company’s prior unconsolidated investment in Citrus.

98. 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 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 ~~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 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 The ~~2011, the~~ Company ~~entered~~has ~~into~~outstanding interest rate swap agreements to hedge ~~the~~floating ~~$600~~rate ~~million~~notes ~~Junior Subordinated Notes due 2066~~ with an aggregate notional amount of $525 million, of which $450 million ~~were~~are for ten-year periods and $75 million ~~were~~are 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 ofnotes based on three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011. The interest rate swaps effectively fix the ~~interest~~floating rate ~~applicable~~LIBOR-based toportion of the ~~floating~~interest ~~rate~~payments on the swapped notes to a ~~portion~~weighted average fixed rate of 3.63%. Prior to the ~~Junior~~ETE ~~Subordinated~~Merger, ~~Notes~~these ~~and~~interest ~~are~~rate swaps 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~~impacted 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 ETE Merger, the Company discontinued hedge accounting treatment on these interest rate swaps. Therefore, changes in fair value ~~were~~since then have been 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 into interest 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.

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Commodity Contracts – Gathering and Processing Segment

The Company primarily ~~enters~~entered 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 March 31, 2013, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 3,437,500 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 March 31, 2013, approximately $3 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 12 months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.13

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Natural Gas Price Swaps. These natural gas price 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 into operating revenues in the same periods during which the forecasted natural gas sales impact earnings. These swaps were terminated in connection with the SUGS Contribution on April 30, 2013.

Commodity Contracts – Distribution Segment

Through the Distribution segment, included in the LDC Disposal Group at ~~March~~June 3130, 2013, 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 ~~March~~June 3130, 2013, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 148,~~030~~300,000 MMBtu, 815,~~160~~110,000 MMBtu and ~~220~~4,470,000 MMBtu for the remainder of 2013, 2014 and 2015, respectively. These natural gas price swaps 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 condensed consolidated balance sheets ~~at the dates indicated~~. The asset and liability derivative instruments belonging to the Distribution segment have been included in current asset and liabilities held for sale at ~~March~~June 3130, 2013.

	Fair Value
	Asset Derivatives				Liability Derivatives
Balance Sheet Location	~~March~~June 3130, 2013		December 31, 2012		~~March~~June 3130, 2013		December 31, 2012
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Natural gas price swaps:
Accounts payable to related companies	$	—	$	—	$	3—	$	5
	—		—		3—		5
Economic Hedges:
Interest rate contracts:
Derivative instruments — liabilities	—		—		18		18
Deferred credits	—		—		5431		59
Commodity contracts — Distribution:
Natural gas price swaps:
Current assets held for sale	81		1		—		—
Non-current assets held for sale	—		1		—		—
Current liabilities held for sale	—		—		25		9
	8		2		74		86
	1		2		54		86
Total	$	81	$	2	$	7754	$	91

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 condensed consolidated balance sheets 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 condensed consolidated financial statements ~~for the periods presented~~:

	Successor						Predecessor
	Three MonthsEndedJune 30, 2013			Three Months EndedJune 30, 2012
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Cash Flow Hedges:
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Interest rate contracts:
Change in fair value — increase in accumulated other comprehensive income	$	(3	)	$	9
Change in fair value — increase in accumulated other comprehensive income	$	—		$	—		$	6
Reclassification of unrealized gain from accumulated other comprehensive income	—			6
Reclassification of unrealized loss from accumulated other comprehensive income — increase of interest expense	—			—			8
Economic Hedges:
Commodity contracts — Gathering and Processing:
Interest rate contracts:
Change in fair value — increase in accumulated other comprehensive income	—			2			5
Change in fair value — increase (decrease) in interest expense	(23		)	20
Reclassification of unrealized gain from accumulated other comprehensive income	—			—			2
Commodity contracts — Distribution:
Economic Hedges:
Change in fair value — increase (decrease) in deferred natural gas purchases	10			(20		)
Interest rate contracts:
Change in fair value — increase in interest expense	5			—			—
Commodity contracts — Distribution:
Change in fair value — decrease in deferred natural gas purchases	(13		)	—			(2		)



	Successor						Predecessor
	Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Cash Flow Hedges:
Interest rate contracts:
Change in fair value — increase in accumulated other comprehensive income	$	—		$	—		$	6
Reclassification of unrealized loss from accumulated other comprehensive income — increase of interest expense	—			—			8
Commodity contracts — Gathering and Processing:
Change in fair value — increase in accumulated other comprehensive income	(3		)	11			5
Reclassification of unrealized gain from accumulated other comprehensive income	—			6			2
Economic Hedges:
Interest rate contracts:
Change in fair value — increase (decrease) in interest expense	(28		)	20			—
Commodity contracts — Distribution:
Change in fair value — decrease in deferred natural gas purchases	(3		)	(20		)	(2		)

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 contingent feature that are in a net liability position at June 30, 2013 was $3 million, all of which were included in the disposal group held for sale at June 30, 2013.

1315

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109. 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 Valueas of		Fair Value Measurements at ~~March~~June 3130, 2013Using Fair Value Hierarchy
	March 31, 2013		Level 1		Level 2		Level 3
	June 30, 2013		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	61	$	—	$	61	$	—
Total	$	61	$	—	$	61	$	—
Liabilities:
Commodity derivatives	$	35	$	—	$	35	$	—
Interest-rate swap derivatives	72		—		72		—
Interest rate swaps	49		—		49		—
Total	$	7554	$	—	$	7554	$	—

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 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 measurements at ~~March~~June 3130, 2013. During ~~and~~the ~~there~~period ~~were~~ended June 30, 2013, no transfers were made between ~~hierarchy~~any levels within the fair value hierarchy.

~~The~~10. ~~approximate~~COMMITMENTS ~~fair~~AND ~~value of the Company’s cash and cash equivalents, accounts receivable and accounts payable is equal to book value, due to their short-term nature.~~CONTINGENCIES:

11. COMMITMENTS AND CONTINGENCIES:

PEPL Holdings Guarantee of Collection

In ~~accordance~~connection with the ~~Contribution Agreement pursuant to which the Company contributed~~ SUGS ~~to Regency~~Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, ~~under the Contribution Agreement~~ and pay certain other expenses or disbursements directly related to the closing of the SUGS ~~contribution~~Contribution. In connection with the closing of the SUGS ~~contribution,~~Contribution on April 30, 2013, Regency entered into ~~the~~an ~~guarantee~~agreement ~~of collection~~ with PEPL Holdings, a subsidiary of the Company, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to the Company) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023.

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 potentially responsible parties. 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.

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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 potentially responsible parties. 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.

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 potentially responsible parties 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 Massachusetts Department of Environment Protection 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 $11 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 condensed consolidated balance sheets.

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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.

	March 31, 2013		December 31, 2012
	June 30, 2013		December 31, 2012
Current	$	73	$	7
Noncurrent	2615		26
Total environmental liabilities	$	3318	$	33

~~Litigation and Other Claims~~17

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 $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Company’s former Vice Chairman, President and Chief Operating Officer, 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.

Litigation Relating to the ETE Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the ETE Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the ETE Merger involves an unfair price and an inadequate sales process, that Southern Union's directors entered into the ETE Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the ETE Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the ETE Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21,

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~~2011,~~Litigation ~~the~~and ~~court~~Other ~~denied ETE's October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.~~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). 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 $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Company’s former Vice Chairman, President and Chief Operating Officer, 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. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. 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.

Litigation Relating to the ETE Merger. In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the ETE Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the ETE Merger involves an unfair price and an inadequate sales process, that Southern Union's directors entered into the ETE Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the ETE Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the ETE Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE's October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

The Texas case remains pending, and discovery is ongoing.

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants' motion for summary judgment. The deadline for the remaining defendants to file an answer or otherwise respond is late April, 2013. Trial in this action is not currently set.18

~~Mercury~~Table ~~Release~~of Contents

In ~~October~~November ~~2004~~2011, ~~New~~a ~~England~~derivative ~~Gas~~lawsuit ~~Company~~was ~~discovered~~filed ~~that~~in ~~one~~the ofJudicial ~~its~~District ~~facilities,~~Court ~~formerly~~of ~~associated~~Harris ~~with~~County, ~~discontinued~~Texas ~~operations~~naming ~~which~~as ~~were~~defendants ~~sold~~ETP, inETP ~~2006~~GP, ~~had~~ETP ~~been~~LLC, ~~broken~~the ~~into~~boards ~~and~~of ~~that~~directors ~~mercury~~of ~~had~~ETP ~~been~~LLC ~~released~~(collectively ~~both~~with ~~inside~~ETP aGP ~~building~~ and inETP LLC, the ~~immediate~~“ETP ~~vicinity~~Defendants”), ~~including~~certain amembers ~~parking~~of ~~lot~~management infor aETP ~~neighborhood~~and ~~several~~ETE, ~~blocks~~ETE, ~~away~~and Southern Union. ~~Mercury~~The ~~from~~lawsuit ~~the~~is ~~parking~~styled ~~lot~~W. ~~was~~J. ~~apparently~~Garrett ~~tracked~~Trust ~~into~~v. ~~nearby~~Bill ~~apartment~~W. ~~units~~Byrne, aset ~~well~~al., asCause ~~other buildings~~No. ~~Cleanup~~ ~~was~~2011-71702, ~~completed~~in at the ~~property~~157th ~~and~~Judicial ~~nearby~~District ~~apartment~~Court ~~units. The~~of ~~vandals~~Harris ~~who~~County, ~~broke~~Texas. Plaintiffs ~~into~~assert ~~the~~claims ~~facility~~for ~~were~~breaches ~~arrested~~of ~~and~~fiduciary ~~convicted. In October 2007~~duty, ~~the~~breaches ~~U.S.~~of ~~Attorney~~contractual induties, ~~Rhode~~and ~~Island~~acts ~~filed~~of abad ~~three-count~~faith ~~indictment~~ against each of the ~~Company~~ETP inDefendants and the Uindividual defendants.S. Plaintiffs ~~District~~also ~~Court~~assert claims for ~~the~~aiding ~~District~~and ofabetting ~~Rhode~~and ~~Island~~tortious ~~(“District~~interference ~~Court”)~~with ~~alleging~~contract ~~violation~~against ofSouthern ~~permitting~~Union. On ~~requirements~~October ~~under~~5, ~~the~~2012, ~~Federal~~certain ~~Resource~~defendants ~~Conservation~~filed ~~and~~a ~~Recovery~~motion ~~Act~~for ~~(“RCRA”)~~summary ~~and~~judgment ~~notification~~with ~~requirements~~respect ~~under~~to the ~~Emergency~~primary ~~Planning~~allegations ~~and~~in ~~Community~~this ~~Right~~action. On toDecember ~~Know~~13, ~~Act~~2012, ~~(“EPCRA”)~~Plaintiffs ~~relating~~filed their opposition to the ~~2004~~motion ~~incident~~for summary judgment. ~~Trial~~Defendants ~~commenced~~filed a reply on ~~September~~December 2219, ~~2008,~~2012. On ~~and~~December ~~on October 15~~20, ~~2008~~2012, the ~~jury~~court ~~acquitted~~conducted ~~Southern~~an ~~Union~~oral hearing on the ~~EPCRA~~motion. Plaintiffs ~~count~~filed ~~and~~a ~~one~~post-hearing ofsur-reply ~~the~~on ~~two~~January ~~RCRA~~7, ~~counts~~2013. On ~~and~~January ~~found~~16, 2013, the ~~Company~~Court ~~guilty~~granted ondefendants' ~~the~~motion ~~other~~for ~~RCRA~~summary ~~count~~judgment. OnThe ~~October~~parties 2,agreed ~~2009,~~to settle the ~~District~~matter ~~Court~~and ~~imposed~~executed a ~~fine~~memorandum of $6understanding. The ~~million~~parties ~~and~~are drafting a ~~payment~~stipulation of ~~$12~~settlement ~~million~~(with proposed judgment) and will have a settlement hearing likely in ~~community~~August ~~service~~2013 for the Court to approve the settlement, which will dispose of the case. It is unlikely the Court will reject the settlement.

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 Resource Conservation and Recovery Act (“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 petitioned the District Court for consideration of the same issues and the hearing took place on December 3, 2012. The District Court has ruled in favor of the Company and limited the penalty to “community service” of up to $500,000.

17Litigation Related to Incident at JJ's Restaurant. On February 19, 2013, there was a natural gas explosion at JJ's Restaurant located at 910 W. 48th Street in Kansas City, Missouri. One person died and media reports indicate that up to fifteen people were transported to area hospitals. The extent and nature of those injuries are currently unknown. The restaurant building was destroyed in the explosion and fire. Immediately surrounding buildings sustained damage, but the full extent of that damage is unknown at this time. A contractor, Heartland Midwest LLC, was in the process of installing cable for Time Warner Cable and hit a natural gas line while directionally boring. The utility locates for the work were done by USIC Locating Services, Inc., a utility infrastructure locating company engaged by Missouri Gas Energy to locate and mark underground gas lines (and engaged by others to mark other underground facilities). Several parties have retained counsel, and to date, nine lawsuits have been filed in the Circuit Court of Jackson County, Missouri, against numerous defendants. MGE and a MGE employee, Michael Palier, are defendants in all but one of the lawsuits (Palier v. Time Warner). The lawsuits filed to date include Simmons v. MGE, Case No. 1316-CV07265 (no trial date set); Tanner v. MGE, Case No. 1316-CV09906 (no trial date set), JJ's Restaurant v. MGE, Case No. 1316-CV11288 (two trial dates set on January 12, 2015 and April 6, 2015); Meek

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~~consideration~~v. ofMGE, ~~the~~Case ~~same~~No. ~~issues~~1316-CV13523 ~~and~~(no ~~the~~trial ~~hearing~~date ~~took~~set); ~~place~~Cramer onv. ~~December~~MGE, 3Case No. 1316-CV13738 (no trial date set); Plazaview, ~~2012~~LLC v. MGE, Case No. 1316-CV16817 (no trial date set); Mingos v. MGE, Case No. 1316-CV18072 (no trial date set); Palier v. Time Warner, Case No. 1316-CV18684 (no trial date set); and Couture v. MGE, Case No. 1316-CV18787 (no trial date set). ~~The~~Discovery ~~District~~in ~~Court~~the ~~has~~pending ~~ruled~~lawsuits is ongoing. No demands have been made in ~~favor~~any of the pending lawsuits. The Company anticipates that more lawsuits will be filed. The Missouri Public Service Commission and ~~limited~~the Occupational Safety and Health Administration investigations are ongoing. The Company will assess its potential exposure as the ~~penalty~~matter toprogresses ~~“community~~as ~~service”~~no ofestimate upcan tobe ~~$500,000~~made at this time.

Simmons v. Southern Union Company. Cause No. 1316-CV-07265, in the Circuit Court of Jackson County, Missouri, Kansas City: On March 22, 2013, the first lawsuit related to the February 19, 2013 natural gas incident at JJ's Restaurant was filed in Missouri state court on behalf of six injured restaurant employees. The defendants include Southern Union Company d/b/a MGE, USIC Locating Services, Inc. (the utility marking service), Heartland Midwest, LLC (the directional boring company and contractor of Time Warner Cable Media, Inc.), Time Warner Cable Media, Inc., Missouri One Call System, Inc., (Missouri's notification center for utility locates), and Mike Palier (MGE's first responder). Plaintiffs' claims include negligence and strict liability for inherently dangerous activities. Plaintiffs have not specified an amount of damages, but seek punitive damages against MGE and certain other defendants in a jury trial. No trial date has been set.

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 ~~March~~June 3130, 2013 and December 31, 2012, the Company recorded litigation and other claim-related accrued liabilities of $2725 million and $27 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 1312 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 (“HAPs”). 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~~In isJanuary ~~required by October~~ 2013~~. It~~, ~~is anticipated that~~ the ~~limits~~EPA ~~adopted~~issued ~~in this rule will be used in~~ a ~~future~~final ~~EPA~~reconsideration rule that isexempted ~~scheduled~~Area toSource beengines ~~finalized~~located in ~~2013,~~remote ~~with~~areas ~~compliance~~from ~~required~~the inemission ~~2016. This~~limits ~~future rule is expected to require reductions in formaldehyde~~ and ~~carbon~~monitoring ~~monoxide~~requirements. Compliance ~~emissions~~is ~~from~~required ~~engines~~by ~~greater~~October ~~than 500 horsepower at Major Sources~~2013.

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 ppb with 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.

18The Company has reviewed 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 segment and the potential costs associated with the installation of emission control systems on its

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~~dioxide~~existing ~~non-attainment areas~~engines. InThe ~~addition,~~ultimate ~~ambient~~costs ~~air~~associated ~~quality~~with ~~modeling~~these ~~may~~activities cannot be ~~required~~estimated towith ~~demonstrate~~any ~~compliance~~certainty ~~with~~at this time, but the ~~new~~Company ~~standard~~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 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 engines11. ~~The~~ ~~ultimate~~REPORTABLE 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.SEGMENTS:

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~~were conducted through SUGS, which was contributed to Regency on April 30, 2013. 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 ~~three~~six months ended ~~March~~June 3130, 2013, the period from Acquisition (March 26, 2012) to ~~March~~June 3130, 2012 and the period from January 1, 2012 to March 25, 2012.

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 the Company’s investment in Regency, unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

The Company reports Segment Adjusted EBITDA as a measure of segment performance. 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.

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.

19The following tables set forth certain selected financial information for the Company’s segments:



	Three Months Ended June 30, 2013		Three Months Ended June 30, 2012
Operating revenues from external customers:
Transportation and Storage	$	232	$	186
Gathering and Processing	81		197
Total segment operating revenues	313		383
Corporate and other activities	3		4
	$	316	$	387

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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
	Six Months Ended June 30, 2013		Period from Acquisition (March 26, 2012) to June 30, 2012		Period from January 1, 2012 to March 25, 2012
Operating revenues from external customers:
Transportation and Storage	$	431	$	199	$	194
Gathering and Processing	271		217		246
Total segment operating revenues	702		416		440
Corporate and other activities	7		2		3
	$	709	$	418	$	443

	Successor					Predecessor
	Three Months EndedMarch 31, 2013		Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Operating revenues from external customers:
Transportation and Storage	$	199	$	13		$	194
Gathering and Processing	190		20			246
Total segment operating revenues	389		33			440
Corporate and other activities	4		(2		)	3
	$	393	$	31		$	443
Depreciation and amortization:
Transportation and Storage	$	42	$	3		$	30
Gathering and Processing	17		1			18
Total segment depreciation and amortization	59		4			48
Corporate and other activities	—		—			1
	$	59	$	4		$	49
Earnings from unconsolidated investments:
Transportation and Storage	$	—	$	—		$	16
Gathering and Processing	—		—			—
Corporate and other activities	1		—			—
	$	1	$	—		$	16

Results from the Distribution segment were included in discontinued operations and therefore were not reflected in the tables above.

Results from the Distribution segment were included in discontinued operations and therefore were not reflected in the table above.



	Three Months Ended June 30, 2013			Three Months Ended June 30, 2012
Segment Adjusted EBITDA:
Transportation and Storage	$	169		$	112
Gathering and Processing	(1		)	22
Distribution	24			25
Corporate and other activities	16			2
Total Segment Adjusted EBITDA	208			161
Depreciation and amortization	(47		)	(66		)
Interest expense	(12		)	(57		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(2		)	(1		)
Other, net	(2		)	1
Earnings from unconsolidated investments	5			1
Adjusted EBITDA attributable to unconsolidated investments	(21		)	(4		)
Adjusted EBITDA attributable to discontinued operations	(23		)	(25		)
Income from continuing operations before income tax expense	$	106		$	10

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	Successor						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
	Six Months EndedJune 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Segment Adjusted EBITDA:
Transportation and Storage	$	~~124~~293		$	~~(33~~79	)	$	186
Gathering and Processing	(67		)	(11		)	25
Distribution	3963			~~(10~~29		)	34
Corporate and other activities	420			(213		)	(19		)
Total Segment Adjusted EBITDA	~~161~~369			~~(56~~106		)	226
Depreciation and amortization	(59106		)	(470		)	(49		)
Interest expense	(45		)	(61		)	(50		)
Net gain on curtailment of OPEB plans	—			15			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(24		)	—(1		)	(1		)
Other, net	(1		)	—1			(2		)
Earnings from unconsolidated investments	16			—1			16
Adjusted EBITDA attributable to unconsolidated investments	(526		)	—(4		)	(61		)
Adjusted EBITDA attributable to discontinued operations	(4063		)	(329		)	(34		)
Interest expense	(33		)	(4		)	(50		)
Income (loss) from continuing operations before income tax expense	$	130		$	(42	)	$	45
Income (loss) from continuing operations before income tax expense	$	24		$	(52	)	$	45

	March 31, 2013		December 31, 2012
	June 30,2013		December 31, 2012
Total assets:
Transportation and Storage	$	6,~~198~~312	$	6,219
Gathering and Processing	2,038		1,965
Gathering and Processing (1)	—		1,965
Distribution (1)	1,224		1,190
Distribution (2)	1,106		1,190
Total segment assets	97,~~460~~418		9,374
Corporate and other activities	~~686~~2,070		619
Total assets	$	109,~~146~~488	$	9,993

(1)~~Distribution~~ ~~segment~~The ~~assets~~Gathering ~~have~~and ~~been~~Processing ~~reported~~segment aswas ~~assets~~contributed ~~held~~to ~~for~~Regency ~~sale~~on inApril ~~the consolidated balance sheets at March 31~~30, 2013. ~~and~~See ~~December~~Note ~~31, 2012~~2.

~~13.~~(2) ~~REGULATION~~Distribution ~~AND~~segment ~~RATES:~~assets have been reported as assets held for sale in the condensed consolidated balance sheets at June 30, 2013 and December 31, 2012.

~~Panhandle~~12. On ~~July~~REGULATION ~~26,~~AND 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; such facilities are contemplated to be converted to crude oil transportation service. This sale is subject to FERC approval. 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.RATES:

InTrunkline ~~November~~Transfer 2011, the FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.Application

~~New England Gas Company.~~ On ~~September~~July 1526, ~~2008~~2012, ~~New~~Trunkline ~~England~~filed ~~Gas~~an ~~Company~~application ~~made a filing~~ with the ~~MDPU~~FERC ~~seeking~~for ~~recovery~~approval ofto transfer approximately $4770 ~~million,~~miles orof ~~50%~~underutilized ofloop ~~the~~piping ~~amount~~facilities by ~~which~~sale ~~its~~to ~~2007~~an ~~earnings~~affiliate; ~~fell~~such ~~below~~facilities aare ~~return~~contemplated onto ~~equity~~be ofconverted ~~7%. This filing was made pursuant~~ to ~~New~~crude ~~England~~oil ~~Gas~~transportation ~~Company’s~~service. ~~rate~~This ~~settlement~~sale ~~approved~~is bysubject ~~the~~to ~~MDPU~~FERC ~~in 2007~~approval. On Several ~~February~~parties 2have intervened, ~~2009~~commented, ~~the~~or ~~MDPU~~protested ~~issued~~this ~~its~~filing. The ~~order denying the~~ Company’s ~~requested~~has ~~earnings~~responded ~~sharing~~to ~~adjustments~~all ~~(“ESA”)~~information inrequests ~~its~~from ~~entirety. The~~the ~~Company~~Commission ~~appealed~~and ~~that~~is ~~decision~~awaiting toa ~~the~~final ~~Massachusetts~~order ~~Supreme~~in ~~Judicial~~this ~~Court (“MSJC”)~~proceeding. On ~~November 13,~~

21Panhandle FERC Audit

In November 2011, the FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. The audit is related to the period from January 1, 2010 through December 31, 2011. A draft audit report was received on July 19, 2013 noting no issues that would have a material impact on the Company’s historical financial position or results of operations.

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~~2009,~~ New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $2 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 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 $2 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. On January 25, 2013, the MDPU issued its order approving the 2008 ESA for $2 million to be recovered over a twelve-month period beginning February 1, 2013, which reflected a reduction of approximately $10,000 from the initial request.Filing

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 $2 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 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 $2 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. On January 25, 2013, the MDPU issued its order approving the 2008 ESA for $2 million to be recovered over a twelve-month period beginning February 1, 2013, which reflected a reduction of approximately $10,000 from the initial request.

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

AND RESULTS OF OPERATIONS

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

The information in Item 2 has been prepared pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q. Accordingly, this Item 2 includes only management’s narrative analysis of the results of operations and certain supplemental information.

References to “we,” “us,” “our”, the “Company” and “Southern Union” shall mean Southern Union Company and its subsidiaries.

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 1211 to our condensed consolidated financial statements.

The ETE 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.

The most significant impacts of the new basis of accounting going forward are ~~expected to be~~ (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 the successor and predecessor periods reflect 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 reports Segment Adjusted EBITDA as a measure of segment performance. 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. Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Company's proportionate ownership and amounts for less -than -wholly -owned subsidiaries based on 100% of the subsidiaries' results of operations.

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RECENT DEVELOPMENTS

Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of the Company’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, the Company entered into intercompany notes payable to ETP, which provide for the reimbursement by the Company of ETP’s payments under the newly issued notes.

SUGS Contribution

On April 30, 2013, the Company completed its contribution to Regency of all of the ~~issued and outstanding~~ membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $463 million in cash to the Company, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Company used a portion of the cash consideration to pay down $240 million in outstanding borrowings on the Southern Union Credit Facility. In addition, PEPL Holdings, a wholly-owned subsidiary of the Company, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution, as further discussed in Note 10. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.

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connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to the Company, (ii) the issuance of approximately 6.3 million Regency Class F units to the Company, (iii) the distribution of $570 million in cash to the Company, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration to the Company was reduced by $107 million in estimated closing adjustments. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the Contribution Agreement. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Company has not presented SUGS as discontinued operations due to the expected continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency received as consideration.

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RESULTS OF OPERATIONS

The following ~~table~~tables ~~provides~~provide a reconciliation of Segment Adjusted EBITDA (by segment) to net income ~~for the periods presented.~~:

	Successor						Predecessor
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Segment Adjusted EBITDA:
Segment Adjusted EBITDA:
Transportation and storage segment	$	169		$	112
Transportation and storage segment	$	124		$	(33	)	$	186
Gathering and processing segment	(1		)	22
Gathering and processing segment	(6		)	(11		)	25
Distribution segment	24			25
Distribution segment	39			(10		)	34
Corporate and other activities	16			2
Corporate and other activities	4			(2		)	(19		)
Total Segment Adjusted EBITDA	208			161
Total Segment Adjusted EBITDA	161			(56		)	226
Depreciation and amortization	(47		)	(66		)
Depreciation and amortization	(59		)	(4		)	(49		)
Interest expense	(12		)	(57		)
Interest expense	(33		)	(4		)	(50		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(2		)	(1		)
Non-cash compensation expense, accretion expense and amortization of regulatory assets	(2		)	—			(1		)
Other, net	(2		)	1
Net gain on curtailment of OPEB plans	—			15			—
Earnings from unconsolidated investments	5			1
Other, net	1			—			(2		)
Adjusted EBITDA attributable to unconsolidated investments	(21		)	(4		)
Earnings from unconsolidated investments	1			—			16
Adjusted EBITDA attributable to discontinued operations	(23		)	(25		)
Adjusted EBITDA attributable to unconsolidated investments	(5		)	—			(61		)
Income from continuing operations before income tax expense	106			10
Adjusted EBITDA attributable to discontinued operations	(40		)	(3		)	(34		)
Income tax expense	75			6
Income (loss) from continuing operations before income tax expense	24			(52		)	45
Income from continuing operations	31			4
Income tax expense (benefit)	10			(12		)	12
Income from discontinued operations	9			8
Income (loss) from continuing operations	14			(40		)	33
Net income	$	40		$	12
Income from discontinued operations	22			1			17
Net income (loss)	$	36		$	(39	)	$	50

2326

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	Successor						Predecessor
	Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Segment Adjusted EBITDA:
Transportation and storage segment	$	293		$	79		$	186
Gathering and processing segment	(7		)	11			25
Distribution segment	63			29			34
Corporate and other activities	20			(13		)	(19		)
Total Segment Adjusted EBITDA	369			106			226
Depreciation and amortization	(106		)	(70		)	(49		)
Interest expense	(45		)	(61		)	(50		)
Non-cash compensation expense, accretion expense and amortization of regulatory assets	(4		)	(1		)	(1		)
Net gain on curtailment of OPEB plans	—			15			—
Other, net	(1		)	1			(2		)
Earnings from unconsolidated investments	6			1			16
Adjusted EBITDA attributable to unconsolidated investments	(26		)	(4		)	(61		)
Adjusted EBITDA attributable to discontinued operations	(63		)	(29		)	(34		)
Income (loss) from continuing operations before income tax expense	130			(42		)	45
Income tax expense (benefit)	85			(6		)	12
Income (loss) from continuing operations	45			(36		)	33
Income from discontinued operations	31			9			17
Net income (loss)	$	76		$	(27	)	$	50

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:


•	Incremental depreciation and amortization expense 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 $10 million per quarter subsequent to March 25, 2012.

• In addition to the impact of the amortization of the debt fair value adjustments, interest expense was ~~also~~ lower during the ~~three~~six months ended ~~March~~June 3130, 2013 due to repayments of long-term debt in 2012 and 2013. Additionally, interest expense for the six months ended June 30, 2013 included a $20 million gain 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.

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, 2012.

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Federal and State Income Taxes

The following table sets forth the Company’s income taxes from continuing operations ~~for the periods presented.~~:

	Successor							~~Predecessor~~						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012			Six Months EndedJune 30, 2013				Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Income tax expense (benefit)	$	1075		$	~~(12~~6	)	$	$85	12		$	(6	)	$	12
Effective tax rate	4171		%	2360		%	65	27	%	%	14		%	27		%

The Company’s effective income tax rate for the ~~period~~three and six months ended ~~March~~June 3130, 2013 was higher than the federal statutory rate of 35% primarily due to state income taxes resulting from the SUGS Contribution and other internal restructuring activities. The effective income tax rate for the period from March 26, 2012 to ~~March~~June 3130, 2012 was lower than the federal statutory rate primarily due to the Company’s pre-tax loss as a result of merger-related expenses coupled with non-deductible executive compensation included in the merger-related expenses. The effective income tax rate for the period from January 1, 2012 to March 25, 2012 was lower than the federal statutory rate primarily due to the dividend received reduction for the anticipated receipt of dividends associated with the earnings from the Company’s prior unconsolidated investment in Citrus.

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, Gulf Coast and Midcontinent United States, and LNG terminalling and regasification services. The Transportation and Storage segment’s operations are regulated as to rates and other matters by the 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.

The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers. 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-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.

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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 the 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.~~28

	Successor						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Operating revenues (1)	$	199		$	13		$	194
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(67		)	(46		)	(60		)
Taxes other than on income and revenues	(8		)	—			(9		)
Adjusted EBITDA related to unconsolidated investments	—			—			61
Segment Adjusted EBITDA	$	124		$	(33	)	$	186
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	177			9			152
Trunkline	180			12			177
Sea Robin	40			2			20

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~~(1)~~The ~~Reservation~~following ~~revenues~~table ~~comprised~~illustrates ~~89% of total operating revenues for~~ the ~~three~~results ~~months ended March 31, 2013. Reservation revenues comprised 88%~~ of ~~total~~operations ~~operating~~applicable ~~revenues~~to ~~in both~~ the ~~successor~~Company’s Transportation and ~~predecessor~~Storage ~~periods in 2012.~~segment:



	Successor												Predecessor
	Three Months Ended June 30, 2013			Three Months Ended June 30, 2012			Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Operating revenues⁽¹⁾	$	232		$	186		$	431		$	199		$	194
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(55		)	(64		)	(122		)	(110		)	(60		)
Taxes other than on income and revenues	(8		)	(10		)	(16		)	(10		)	(9		)
Adjusted EBITDA related to unconsolidated investments	—			—			—			—			61
Segment Adjusted EBITDA	$	169		$	112		$	293		$	79		$	186

Panhandle natural gas volumes transported (TBtu):⁽²⁾
PEPL	137			131			314			140			152
Trunkline	177			173			357			185			177
Sea Robin	34			21			74			23			20


⁽¹⁾	Reservation revenues comprised 91% and 89% of total operating revenues for the three months ended June 30, 2013 and 2012, respectively. Reservation revenues comprised 90% of total operating revenues for the six months ended June 30, 2013. Reservation revenues comprised 89% and 88% of total operating revenues in the successor and predecessor periods in 2012, 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.

• Operating Revenues. Operating revenues for the three and six months ended ~~March~~June 3130, 2013 ~~decreased~~increased ~~slightly~~ compared to the ~~predecessor~~successor and ~~successor~~predecessor periods in 2012 primarily due to ~~lower~~the ~~capacity~~recognition ~~sold~~of at$52 ~~lower~~million ~~rates~~received ~~and~~in ~~lower~~connection ~~parking~~with ~~revenues,~~ the ~~impacts~~buyout of ~~which~~a ~~were~~customer’s ~~partially~~contract ~~offset~~as bywell as higher usage revenues of $2 million and $4 million, respectively, as a result of higher volumes, partially offset by lower capacity sold at overall average lower rates and lower parking revenues.

• Operating, Maintenance and General Expenses. The period from March 26, 2012 to ~~March~~June 3130, 2012 included $4143 million of merger-related employee severance expenses. The remaining decrease in operating expenses for the six months ended June 30, 2013 compared to the prior periods is primarily attributable to a decrease in employee-related costs related to integration efforts subsequent to ETE’s acquisition of Southern Union.

•

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 on March 26, 2012. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for the predecessor period shown above but was not reflected in the successor periods. The period from January 1, 2012 to March 25, 2012 reflected Adjusted EBITDA attributable to Citrus of $61 million.

Gathering and Processing Segment

The Gathering and Processing segment iswas primarily engaged in connecting producing wells of exploration and production companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations ~~are~~were conducted through SUGS, which was contributed to Regency on April 30, 2013. SUGS’ natural gas supply contracts primarily ~~include~~included fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts. These natural gas supply contracts ~~vary~~varied 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~~included exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies. With respect to customer demand for the products and services it

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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 iswas not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers ~~can~~could behave been adversely impacted by severe weather.

The majority of SUGS’ gross margin iswas derived from the sale of NGL and natural gas equity volumes and fee-based services. The prices of NGL and natural gas ~~are~~were 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~~monitored these risks and ~~manages~~managed 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 98 to our condensed consolidated financial statements.

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

	Successor							~~Predecessor~~						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
	Three Months EndedJune 30, 2013			Three Months EndedJune 30, 2012			Six Months EndedJune 30, 2013				Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Operating revenues	$	~~190~~81		$	20197		$	$271	~~246~~		$	217		$	246
Cost of natural gas and other energy (1)	(~~157~~66		)	(14149		)	(223	~~(196~~	)	)	(163		)	(196		)
Gross margin (2)	3315			648			48	50			54			50
Operating, maintenance and general, excluding non-cash compensation expense and accretion	(3716		)	(1724		)	(53	~~(23~~	)	)	(41		)	(23		)
Taxes other than on income and revenues	(2—		)	—(2		)	(2	(2	)	)	(2		)	(2		)
Segment Adjusted EBITDA	$	(61	)	$	~~(11~~22	)	$	$(7	25)		$	11		$	25
Operating Information:
Volumes:
Avg natural gas processed (MMBtu/d)	461,847			453,614				451,893
Avg NGL produced (gallons/d)	1,666,592			1,650,345				1,624,666
Avg natural gas wellhead volumes (MMBtu/d)	480,549			481,881				504,822
Natural gas sales (MMBtu)	19,148,879			1,324,080				18,537,127
NGL sales (gallons)	142,438,132			11,827,811				165,589,355
Average Pricing:
Realized natural gas ($/MMBtu) (3)	$	3.40		$	2.44			$	2.44
Realized NGL ($/gallon) (3)	0.85			1.17				1.17
Natural Gas Daily Waha ($/MMBtu)	3.42			2.40				2.43
Natural Gas Daily El Paso ($/MMBtu)	3.42			2.39				2.42
Estimated plant processing spread ($/gallon)	0.54			0.99				0.96


⁽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 variances impacting Segment Adjusted EBITDA for the Company’s Gathering and Processing segment.

• Gross Margin. Gross margin for the three and six months ended ~~March~~June 3130, 2013 decreased ~~compared~~primarily due to the ~~predecessor~~contribution ~~and~~of ~~successor~~SUGS ~~periods~~to inRegency ~~2012~~on ~~due~~April to30, ~~decreases~~2013. inThis ~~natural~~change ~~gas~~was ~~and~~partially ~~NGL~~offset ~~sales~~by ~~volumes and~~ a ~~decrease~~favorable inimpact ~~market-driven~~from ~~realized average NGL prices. Realized average~~ natural gas and NGL prices ~~were $3~~.40 per MMBtu and $0.85 per gallon for the three months ended March 31, 2013, compared to $2.44 per MMBtu and $1.17 per gallon for the period from March 26, 2012 to March 31, 2012 and $2.44 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012.

• Operating, Maintenance and General Expenses. Operating, maintenance and general expenses reflected increases between periods due to the expansion of the SUGS system, offset by the impact of the contribution of SUGS to Regency on April 30, 2013. Additionally, the period from March 26, 2012 to June 30, 2012 included $16 million in merger-related employee severance expenses.

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• Operating, Maintenance and General Expenses. Operating, maintenance and general expenses increased during the three months ended March 31, 2013 due to expansion of the SUGS system. This change was offset by the absence of $15 million in merger-related employee severance expenses that were incurred during the period from March 26, 2012 to March 31, 2012.

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 operations of the Distribution segment have been classified as discontinued operations at ~~March~~June 3130, 2013. 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, see Note 1312 to our condensed consolidated financial statements.

~~The following table illustrates the results of operations applicable to the Company’s Distribution segment for the periods presented.~~30

	Successor						Predecessor
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Amounts reported within discontinued operations:
Net operating revenues (1)	$	73		$	5		$	66
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(30		)	(14		)	(29		)
Taxes other than on income and revenues	(4		)	(1		)	(3		)
Segment Adjusted EBITDA	$	39		$	(10	)	$	34
Operating Information:
Natural gas sales volumes (MMcf)	27,629			2,177			19,957
Natural gas transported volumes (MMcf)	8,657			629			7,379
Weather – Degree Days: (2)
Missouri Gas Energy service territories	2,676			1			1,898
New England Gas Company service territories	2,309			139			2,170

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The following table illustrates the results of operations applicable to the Company’s Distribution segment:



	Successor												Predecessor
	Three Months Ended June 30, 2013			Three Months Ended June 30, 2012			Six Months Ended June 30, 2013			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012
Amounts reported within discontinued operations:
Net operating revenues ⁽¹⁾	$	57		$	56		$	130		$	61		$	66
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(30		)	(28		)	(60		)	(28		)	(29		)
Taxes other than on income and revenues	(3		)	(3		)	(7		)	(4		)	(3		)
Segment Adjusted EBITDA	$	24		$	25		$	63		$	29		$	34

Operating Information:
Natural gas sales volumes (MMcf)	10,733			4,983			38,362			7,160			19,957
Natural gas transported volumes (MMcf)	6,178			8,494			14,835			9,123			7,379
Weather – Degree Days: ⁽²⁾
Missouri Gas Energy service territories	619			242			3,295			243			1,898
New England Gas Company service territories	1,082			599			3,391			738			2,170

⁽¹⁾ Operating revenues for the Distribution segment were 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 mean temperature for a day falls below 65 degrees Fahrenheit.

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

• Net Operating Revenues. The three and six months ended ~~March~~June 3130, 2013 were slightly higher compared to the ~~predecessor~~three and ~~successor~~six ~~periods~~months inended June 30, 2012 primarily due to colder-than-normal temperatures and a longer heating season.

• Operating, Maintenance and General Expenses. ~~This~~The ~~decrease~~period ~~was~~from ~~primarily~~March ~~due~~26, 2012 to June 30, 2012 included $12 million in merger-related expenses ~~incurred during the period from March 26, 2012 to March 31, 2012~~.

Corporate and Other Activities

The period from January 1, 2012 to March 25, 2012 included $19 million in merger-related expenses.

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Supplemental Pro Forma Financial Information

The following unaudited pro forma condensed 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 ~~three~~six months ended ~~March~~June 3130, 2012, giving effect to the ETE Merger as if it had occurred on January 1, 2012. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if these transactions had been consummated on January 1, 2012.

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012			Pro Forma Adjustments				Pro Forma Three Months Ended March 31, 2012
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Pro Forma Adjustments				Pro Forma Six Months Ended June 30, 2012
OPERATING REVENUES	$	31418		$	443		$	—			$	~~474~~861
OPERATING EXPENSES:
Cost of natural gas and other energy	14165			197							~~211~~362
Operating, maintenance and general	61166			116			(72		)	(a)	~~105~~210
Depreciation and amortization	470			49			6			(b)	59125
Total operating expenses	79401			362			(66		)		~~375~~697
OPERATING INCOME	~~(48~~17		)	81			66				99164
OTHER INCOME (EXPENSE):
Interest expense	(461		)	(50		)	9			(c)	(45102		)
Earnings from unconsolidated investments	—1			16			(9		)	(d)	78
Other, net	—1			(2		)	—				(21		)
Total other expenses, net	(459		)	(36		)	—				(4095		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	(5242		)	45			66				5969
Income tax expense (benefit)	(126		)	12			23			(e)	2329
INCOME (LOSS) FROM CONTINUING OPERATIONS	(4036		)	33			43				3640
Income from discontinued operations	19			17			—				1826
NET INCOME (LOSS)	$	(3927	)	$	50		$	43			$	5466


(a)	To eliminate 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.

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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.

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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 ~~March~~June 3130, 2013.

Changes In Internal Control Over Financial Reporting

~~Subsequent~~There tohave ~~the~~been ~~merger~~no ~~with~~changes ~~ETE~~ in ~~March~~our ~~2012, the Company's~~ internal controls over financial reporting, ~~including~~(as ~~certain~~defined ~~disclosure~~in ~~controls~~Rule ~~and~~13(a)-15(f) ~~corporate~~or ~~governance~~Rule ~~procedures,~~15d-15(f) ~~have~~of ~~been impacted by changes made to conform to~~ the ~~existing~~Exchange ~~controls~~Act) ofduring ~~ETP and ETE. During~~ the three months ended ~~March~~June 3130, 2013, ~~the Company's accounting systems were transitioned to the accounting systems of ETP and ETE and accordingly certain controls changed at~~ that ~~time. None~~have ofmaterially ~~these~~affected, ~~changes~~or are inreasonably ~~response~~likely to ~~any~~materially ~~identified~~affect, ~~deficiency~~our ~~or weakness in the Company's~~ internal ~~control~~controls 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 1110 in this Quarterly Report on Form 10-Q and in Note 14 included in the Company’s Form 10-K for the year ended December 31, 2012.

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 1110 in this Quarterly Report on Form 10-Q and Note 14 included in the Company’s Form 10-K for the year ended December 31, 2012.

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 March 1, 2013.

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ITEM 6. EXHIBITS

The ~~following~~ exhibits listed below are filed as part of this ~~Quarterly~~ report ~~on Form 10-Q~~:

Exhibit No.
	ExhibitNumber	Description
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(*)	2.1	Contribution Agreement dated as of February 27, 2013 by and among Southern Union Company, Regency Energy Partners LP, Regency Western G&P LLC, and for certain limited purposes, ETP Holdco Corporation, Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and ETC Texas Pipeline, Ltd (Filed as Exhibit 2.1 to Southern Union’s Current Report on Form 8-K filed on May 8th, 2013).
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(*)	4.1	Registration Rights Agreement, dated April 30, 2013, by and between Southern Union Company and Regency Energy Partners LP (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K filed on May 6th, 2013).
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(*)	4.2	Supplemental Indenture No. 3, dated June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A, as trustee (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K filed on June 26, 2013).
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(*)	4.3	Supplemental Indenture No. 4, dated June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Filed as Exhibit 4.2 to Southern Union’s Current Report on Form 8-K filed on June 26, 2013).
101.INS	XBRL Instance Document
(*)	4.4	Third Supplemental Indenture, dated June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as trustee (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K filed on June 26, 2013).
101.SCH	XBRL Taxonomy Extension Schema Document
(*)	10.1	Guarantee of Collection, dated as of April 30, 2013, by and between Regency Energy Partners LP and PEPL Holdings, LLC (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on May 6th, 2013).
101.CAL	XBRL Taxonomy Calculation Linkbase Document
	31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
101.DEF	XBRL Taxonomy Extension Definitions Document
	31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
101.LAB	XBRL Taxonomy Label Linkbase Document
(**)	32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.PRE	XBRL Taxonomy Presentation Linkbase Document
(**)	32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.INS	XBRL Instance Document
	101.SCH	XBRL Taxonomy Extension Schema Document
	101.CAL	XBRL Taxonomy Calculation Linkbase Document
	101.DEF	XBRL Taxonomy Extension Definitions Document
	101.LAB	XBRL Taxonomy Label Linkbase Document
	101.PRE	XBRL Taxonomy Presentation Linkbase Document

30* Indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise. ** Furnished herewith.

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) 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:	~~May~~August 98, 2013	By:	/s/ Martin Salinas, Jr.
			Martin Salinas, Jr.
			Chief Financial Officer (duly authorized to sign on behalf of the registrant)

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