Filing Compare · SOUTHERN UNION CO

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

~~For~~x ~~the~~QUARTERLY ~~quarterly~~REPORT ~~period~~PURSUANT ~~ended~~TO ~~September 30,~~SECTION ~~2012~~13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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(State or other jurisdiction ofincorporation or organization) 75-0571592(I.R.S. EmployerIdentification No.) 5051 Westheimer RoadHouston, Texas 77056-5622 (Address of principal executive offices) (Zip code)



Delaware	75-0571592
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

(713) 989-2000



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

(Registrant’s telephone number, including area code: (214) 981-0700

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes 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~~Indicate ~~accelerated~~by ~~filer x Accelerated~~check ~~filer~~mark ~~¨ Non-accelerated~~whether ~~filer~~the ~~¨ Smaller~~registrant ~~reporting~~is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

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

~~FORM~~Table ~~10-Q~~of Contents

September 30, 2012

SOUTHERN UNION COMPANY AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
		PAGE
PART I. FINANCIAL INFORMATION
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements (Unaudited)		1
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)
Condensed Consolidated Balance Sheet		2
	Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statement of Operations		4
	Condensed Consolidated Statements of Operations	3
~~Condensed Consolidated Statements of Comprehensive Income (Loss)~~	Condensed Consolidated Statements of Comprehensive Income (Loss)	54
Condensed Consolidated Statement of Stockholders' Equity		6
	Condensed Consolidated Statement of Stockholder’s Equity	5
~~Condensed Consolidated Statements of Cash Flows~~	Condensed Consolidated Statements of Cash Flows	76
Notes to Consolidated Financial Statements		8
	Notes to Condensed Consolidated Financial Statements	7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		41
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	29
ITEM 4. Controls and Procedures		41
ITEM 4.	CONTROLS AND PROCEDURES	29
PART II. OTHER INFORMATION		42
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings		42
ITEM 1.	LEGAL PROCEEDINGS	29
ITEM 1A. Risk Factors		42
ITEM 1A.	RISK FACTORS	29
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		42
ITEM 6.	EXHIBITS	30
ITEM 3. Defaults Upon Senior Securities		42
SIGNATURE		31
ITEM 4. Mine Safety Disclosures		42
ITEM 5. Other Information		42
ITEM 6. Exhibits		43
SIGNATURE		44

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 ~~Southern~~the ~~Union~~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,” “~~project~~believe,” “~~expect~~intend,” “~~plan~~project,” “~~goal~~plan,” “~~forecast~~expect,” “~~estimate~~continue,” “~~intend~~estimate,” “~~continue~~goal,” “~~believe~~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, ~~estimated or expressed~~projected, forecasted, ~~projected~~estimated or ~~expected~~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, ~~2011~~2012 filed with the Securities and Exchange Commission on ~~February 24~~March 1, ~~2012~~2013.

Definitions

The ~~abbreviations,~~following is a list of certain acronyms and ~~industry~~terms ~~terminology~~generally used in ~~these~~the ~~financial~~energy ~~statements~~industry onand ~~Form~~throughout ~~10-Q~~this ~~are defined as follows~~document:

Btu British thermal units



/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

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

CEO Chief Executive Officer

CFO Chief Financial Officer

Citrus Citrus Corp.

Company Southern Union and its subsidiaries

EITR Effective income tax rate

EPA United States Environmental Protection Agency

ETE Energy Transfer Equity, L.P.

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

Exchange Act Securities Exchange Act of 1934

FERC Federal Energy Regulatory Commission

Florida Gas Florida Gas Transmission Company, LLC

GAAP Accounting principles generally accepted in the United States of America

Gallons/d gallons per day

Holdco ETP Holdco Corporation

LIBOR London Interbank Offer Rate

LNG Liquefied natural gas

LNG Holdings Trunkline LNG Holdings, LLC

MADEP Massachusetts Department of Environmental Protection

MDPU Massachusetts Department of Public Utilities

MGPs Manufactured gas plants

MMBtu Million British thermal units

MMBtu/d Million British thermal units per day

MMcf Million cubic feet

MMcf/d Million cubic feet per day

MPSC Missouri Public Service Commission

NGL Natural gas liquids

NMED New Mexico Environment Department

OPEB plans Other postretirement employee benefit plans

Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs Polychlorinated biphenyls

PEPL Panhandle Eastern Pipe Line Company, LP

PEPL Holdings PEPL Holdings, LLC

ppb parts per billion

PRPs Potentially responsible parties

RCRA Resource Conservation and Recovery Act

Sea Robin Sea Robin Pipeline Company, LLC

SEC United States Securities and Exchange Commission

~~Sigma Sigma~~Table ~~Acquisition~~of ~~Corporation~~Contents

~~Southern~~MGP ~~Union~~ 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

~~SUGS Southern~~Adjusted ~~Union~~EBITDA ~~Gas~~is ~~Services~~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.

Sunoco Sunoco, Inc.

TBtu Trillion British thermal units

TCEQ Texas Commission on Environmental Quality

Trunkline Trunkline Gas Company, LLC

Trunkline LNG Trunkline LNG Company, LLC

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA includes amounts for less than wholly owned subsidiaries and unconsolidated affiliates based on the Company's proportionate ownership.

iii

~~PART~~Table Iof ~~- FINANCIAL INFORMATION~~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. ~~See Note 3 to our condensed consolidated financial statements for a discussion of the estimated fair values of assets and liabilities recorded in connection with the ETE Merger.~~

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	165		$	49
Accounts receivable, net	151			155
Accounts receivable from related companies	80			72
Inventories	169			163
Exchanges receivable	25			11
Current assets held for sale	136			184
Prepayments and other assets	149			120
Total current assets	875			754
PROPERTY, PLANT AND EQUIPMENT:
Plant in service	5,616			5,491
Construction work in progress	226			272
	5,842			5,763
Accumulated depreciation and amortization	(165		)	(105		)
Net property, plant and equipment	5,677			5,658
NON-CURRENT ASSETS HELD FOR SALE	992			985
DEFERRED CHARGES	69			65
UNCONSOLIDATED INVESTMENTS	114			115
GOODWILL	2,364			2,364
OTHER NON-CURRENT ASSETS	55			52
Total assets	$	10,146		$	9,993

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in ~~thousands~~millions)

(unaudited)

	Successor				Predecessor
	March 31, 2013			December 31, 2012
	September 30, 2012				December 31, 2011
LIABILITIES AND EQUITY
ASSETS
CURRENT LIABILITIES:
CURRENT ASSETS:
Current maturities of long–term debt	$	256		$	259
Cash and cash equivalents	$	7,027			$	23,640
Accounts payable and accrued liabilities	197			118
Accounts receivable net of allowances of $1,352 and $2,325, respectively	160,697				270,741
Accounts payable to related companies	148			110
Accounts receivable — affiliates	14,004				10,467
Federal, state and local taxes payable	20			16
Inventories	192,117				204,235
Accrued interest	41			32
Deferred natural gas purchases	47,596				50,716
Exchanges payable	146			133
Natural gas imbalances — receivable	25,520				54,549
Derivative instruments	18			18
Prepayments and other assets	34,263				42,675
Current liabilities held for sale	80			85
Total current assets	481,224				657,023
Other	40			108
PROPERTY, PLANT AND EQUIPMENT:
Total current liabilities	946			879
Plant in service	6,908,730				7,195,747
LONG-TERM DEBT, less current maturities	3,048			3,024
Construction work in progress	181,301				103,862
DEFERRED CREDITS	335			330
	7,090,031				7,299,609
DEFERRED INCOME TAXES	1,641			1,590
Accumulated depreciation and amortization	(124,877		)		(1,573,273		)
NON-CURRENT LIABILITIES HELD FOR SALE	142			142
Net property, plant and equipment	6,965,154				5,726,336
COMMITMENTS AND CONTINGENCIES (Note 11)
DEFERRED CHARGES:
STOCKHOLDER’S EQUITY:
Regulatory assets	129,512				57,447
Premium on capital stock	4,079			4,079
Other deferred charges	80,122				60,407
Accumulated other comprehensive loss	(25		)	(25		)
Total deferred charges	209,634				117,854
Accumulated deficit	(20		)	(26		)
UNCONSOLIDATED INVESTMENTS	122,932				1,633,289
Total stockholder’s equity	4,034			4,028
GOODWILL	2,030,271				89,227
Total liabilities and stockholder’s equity	$	10,146		$	9,993
OTHER NON-CURRENT ASSETS	70,597				47,130
Total assets	$	9,879,812			$	8,270,859

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED ~~BALANCE~~STATEMENTS ~~SHEETS~~OF OPERATIONS

(Dollars ~~and units~~ in ~~thousands, except par value~~millions)

(unaudited)

	Successor				~~Predecessor~~			Predecessor
	September 30, 2012				December 31, 2011
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
LIABILITIES AND EQUITY
OPERATING REVENUES	$	393		$	31			$	443
CURRENT LIABILITIES:
OPERATING EXPENSES:
Current portion of long–term debt	$	261,351			$	343,254
Cost of natural gas and other energy	159			14				197
Notes payable	—				200,000
Operating, maintenance and general	120			61				116
Notes payable — related party	166,217				—
Depreciation and amortization	59			4				49
Accounts payable and accrued liabilities	109,364				193,949
Total operating expenses	338			79				362
Accounts payable and accrued liabilities — related parties	32,251				178
OPERATING INCOME (LOSS)	55			(48		)		81
Federal, state and local taxes payable	49,879				37,127
OTHER INCOME (EXPENSE):
Accrued interest	41,568				33,837
Interest expense, net of interest capitalized	(33		)	(4		)		(50		)
Natural gas imbalances — payable	98,677				145,212
Earnings from unconsolidated investments	1			—				16
Derivative instruments	25,267				58,598
Other, net	1			—				(2		)
Other	109,732				112,135
Total other expenses, net	(31		)	(4		)		(36		)
Total current liabilities	894,306				1,124,290
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	24			(52		)		45
LONG-TERM DEBT, less current portion	3,093,825				3,160,372
Income tax expense (benefit) from continuing operations	10			(12		)		12
DEFERRED CREDITS	349,845				301,709
INCOME (LOSS) FROM CONTINUING OPERATIONS	14			(40		)		33
DEFERRED INCOME TAXES	1,707,225				1,044,877
Income from discontinued operations	22			1				17
COMMITMENTS AND CONTINGENCIES (Note 11)
NET INCOME (LOSS)	$	36		$	(39	)		$	50
STOCKHOLDER'S EQUITY:
Common stock, $0.01 and $1 par value; 1 and 200,000 shares authorized; 1 and 126,142 shares issued, respectively	—				126,142
Premium on capital stock	3,913,143				1,934,102
Less: Treasury stock, nil and 1,298 shares, respectively, at cost	—				(33,228		)
Less: Common stock held in trust, 1 and 581 shares, respectively	—				(10,888		)
Deferred compensation plans	—				10,888
Accumulated other comprehensive loss	(3,736		)		(119,192		)
Retained earnings (accumulated deficit)	(74,796		)		731,787
Total stockholders' equity	3,834,611				2,639,611
Total liabilities and stockholders' equity	$	9,879,812			$	8,270,859

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

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

(Dollars in ~~thousands~~millions)

(unaudited)

	Successor				~~Predecessor~~			Predecessor
	Three months ended September 30, 2012				Three months ended September 30, 2011
	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	$	477,896			$	617,211
Net income (loss)	$	36		$	(39	)		$	50
OPERATING EXPENSES:
Other comprehensive income, net of tax:
Cost of natural gas and other energy	180,733				304,535
Change in fair value of interest rate hedges	—			—				4
Operating, maintenance and general	121,325				125,710
Reclassification of unrealized loss on interest rate hedges into earnings	—			—				5
Depreciation and amortization	75,710				59,327
Change in fair value of commodity hedges	—			1				3
Revenue–related taxes	3,835				4,268
Reclassification of unrealized (gain) loss on commodity hedges into earnings	—			—				(1		)
Taxes, other than on income and revenues	14,575				12,845
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			—				1
Total operating expenses	396,178				506,685
	—			1				12
OPERATING INCOME	81,718				110,526
Comprehensive income (loss)	$	36		$	(38	)		$	62
OTHER INCOME (EXPENSE):
Interest expense	(34,639		)		(54,925		)
Earnings (losses) from unconsolidated investments	(1,065		)		26,686
Other, net	(69		)		191
Total other expenses, net	(35,773		)		(28,048		)
INCOME BEFORE INCOME TAX EXPENSE	45,945				82,478
Income tax expense	28,959				24,446
NET INCOME	$	16,986			$	58,032

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

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

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

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

(Dollars in ~~thousands~~millions)

(unaudited)

	Successor				Predecessor
	Premium on Capital Stock			Accumulated Other Comprehensive Loss				Accumulated Deficit			TotalStockholder’sEquity
	Three months ended September 30, 2012				Three months ended September 30, 2011
Balance, December 31, 2012	$	4,079		$	(25	)		$	(26	)	$	4,028
Net income	$	16,986			$	58,032
Unit-based compensation	1			—				—			1
Other comprehensive income (loss), net of tax:
Dividends paid on common stock	—			—				(30		)	(30		)
Change in fair value of interest rate hedges	—				(31,586		)
Net income	—			—				36			36
Reclassification of unrealized loss on interest rate hedges into earnings	—				3,421
Other	(1		)	—				—			(1		)
Change in fair value of commodity hedges	(3,534		)		5,395
Balance, March 31, 2013	$	4,079		$	(25	)		$	(20	)	$	4,034
Reclassification of unrealized gain on commodity hedges into earnings	(3,845		)		(3,581		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—				709
Change in other comprehensive income from equity investments	(291		)		35
	(7,670		)		(25,607		)
Comprehensive income	$	9,316			$	32,425

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

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

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~STOCKHOLDERS'~~CASH ~~EQUITY~~FLOWS

~~FOR~~(Dollars ~~THE~~in ~~NINE MONTHS ENDED SEPTEMBER 30, 2012~~millions)

(Dollars in thousands)

(unaudited)

	CommonStock			PremiumonCapitalStock			TreasuryStock,at cost				CommonStockHeldIn Trust			DeferredCompen-sationPlans			AccumulatedOtherComprehensiveIncome (Loss)			RetainedEarnings (Accumu-lated Deficit)			TotalStock-holders'Equity
	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
Balance December 31, 2011	$	126,142		$	1,934,102		$	(33,228	)		$	(10,888	)	$	10,888		$	(119,192	)	$	731,787		$	2,639,611
CASH FLOWS FROM OPERATING ACTIVITES:
Other comprehensive income, net of tax	—			—			—				—			—			12,315			—			12,315
Net income (loss)	$	36		$	(39	)		$	50
Share–based compensation	—			1,654			—				—			—			—			—			1,654
Reconciliation of net income to net cash provided by (used in) operating activities:
Restricted stock issuances	186			(186		)	(2,864		)		—			—			—			—			(2,864		)
Depreciation and amortization (including discontinued operations)	59			5				57
Exercise of stock options	5			79			—				—			—			—			—			84
Deferred income taxes	22			(12		)		23
Contributions to Trust	—			—			—				(399		)	399			—			—			—
Provision for bad debts	1			—				1
Disbursements from Trust	—			—			—				650			(650		)	—			—			—
Amortization of costs charged to interest	(8		)	—				1
Purchase of treasury stock	—			—			(1,450,000		)		—			—			—			—			(1,450,000		)
Net gain on curtailment of OPEB plans	—			(15		)		—
Net income	—			—			—				—			—			—			49,917			49,917
Unrealized gain on derivatives	(5		)	—				—
Balance March 25, 2012	$	126,333		$	1,935,649		$	(1,486,092	)		$	(10,637	)	$	10,637		$	(106,877	)	$	781,704		$	1,250,717
Non-cash compensation expense	2			—				2
Successor
Earnings from unconsolidated investments, net of cash distributions	—			—				(16		)
Balance March 26, 2012	$	—		$	3,912,867		$	—			$	—		$	—		$	—		$	—		$	3,912,867
Changes in operating assets and liabilities, net of merger impact	131			(133		)		79
Other comprehensive loss, net of tax	—			—			—				—			—			(3,736		)	—			(3,736		)
Net cash flows provided by (used in) operating activities	238			(194		)		197
Non-cash compensation expense	—			276			—				—			—			—			—			276
CASH FLOWS FROM INVESTING ACTIVITES:
Dividends paid on common stock	—			—			—				—			—			—			(65,000		)	(65,000		)
Additions to property, plant and equipment	(123		)	(2		)		(60		)
Net loss	—			—			—				—			—			—			(9,796		)	(9,796		)
Loan repayment from unconsolidated investments	—			—				37
Balance September 30, 2012	$	—		$	3,913,143		$	—			$	—		$	—		$	(3,736	)	$	(74,796	)	$	3,834,611
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 ~~Company’s~~accompanying ~~common~~notes ~~stock~~are ~~was~~an $1integral ~~par~~part ~~value in the predecessor period. Therefore, the change in Common Stock, $1 par value, was equivalent to the change in the number~~ of ~~shares~~these ofconsolidated ~~common~~financial ~~stock issued~~statements.

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

Table of Contents

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

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

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in ~~thousands~~millions)

(unaudited)

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


1.	DESCRIPTION OF BUSINESS:

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


•	Transportation and Storage — The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas, and also provides LNG terminalling and regasification services. Its operations expand from the Gulf Coast region throughout the Midwest and Great Lakes region.

• Gathering and Processing — The Gathering and Processing segment is primarily engaged in connecting wells of natural gas producers to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are ~~located~~conducted through SUGS. As discussed in ~~West~~Note ~~Texas~~3, Southern Union completed its contribution of SUGS and ~~Southeast~~its ~~New~~parent ~~Mexico~~company to Regency for approximately $1.50 billion consisting of cash, Regency common units and Regency Class F units on April 30, 2013.

• 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 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 $1.04 billion, subject to customary closing adjustments. 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 Note 3 for information related to the Company’s ~~merger~~disposal ~~with ETE~~ and ~~the~~other ~~completion~~related ~~of the Holdco Transaction~~transactions.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER MATTERS:

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, ~~2011, except as noted below, as a result of the Company's merger with ETE~~2012.

~~Business~~3. ~~Combination~~DISPOSAL ~~Accounting~~AND RELATED TRANSACTIONS:

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

~~Due~~On April 30, 2013, the Company completed its contribution to Regency of all of the ~~application~~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 ~~“push-down”~~(i) ~~accounting~~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’s, ~~financial~~(iii) ~~statements~~the distribution of $570 million in cash to the Company, and ~~certain~~(iv) ~~footnote~~the ~~disclosures~~payment ~~are~~of ~~presented~~$30 million in ~~two~~cash ~~distinct~~to ~~periods~~a subsidiary of ETP. The total cash consideration to ~~indicate~~the Company was reduced by $107 million in estimated closing adjustments. In addition, PEPL Holdings provided a guarantee of collection with respect to the ~~application~~payment of ~~two~~the ~~different~~principal ~~bases~~amounts of ~~accounting. Periods~~Regency’s ~~prior~~debt related to ~~March~~the ~~26,~~Contribution ~~2012~~Agreement. ~~are~~The ~~identified~~Regency ~~herein~~Class F units have the same rights, terms and conditions as ~~“Predecessor~~the Regency common units,” ~~while~~except ~~periods~~that ~~subsequent~~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 ~~ETE~~expected ~~Merger~~continuing ~~are~~involvement ~~identified~~with SUGS through affiliate relationships, as ~~“Successor.”~~well as the direct investment in Regency received as consideration.

~~3. ETE~~Table ~~MERGER~~of ~~AND HOLDCO TRANSACTION:~~Contents

Description of Merger

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Expenses Related to the Merger

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

Allocation of Consideration Transferred

The Merger was accounted for using business combination accounting under applicable accounting principles. Business combination accounting requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

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

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

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

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

Holdco Transaction

On ~~October~~April 530, ~~2012~~2013, ~~ETE and~~ ETP ~~completed~~acquired ~~the~~from ~~Holdco~~ETE ~~Transaction,~~its ~~immediately~~interest ~~following~~in ~~the~~Holdco ~~closing~~for ofapproximately ~~ETP's~~49.5 ~~acquisition~~million of ~~Sunoco~~newly ~~whereby,~~issued ~~(i)~~ETP ~~ETE~~common ~~contributed~~units ~~its~~and ~~interest~~$1.40 billion in ~~Southern~~cash, ~~Union~~less ~~into~~$68 anmillion ~~ETP-controlled entity,~~ in ~~exchange~~estimated ~~for~~closing aadjustments. Holdco ~~60%~~is ~~equity interest in~~ the ~~new~~ entity, ~~Holdco,~~formed ~~and~~by ~~(ii)~~ ETP ~~contributed~~and ~~its~~ETE ~~interest~~ in ~~Sunoco~~2012 to ~~Holdco~~own ~~and~~the ~~retained a 40%~~ equity ~~interest~~interests in ~~Holdco. Pursuant~~Southern toUnion aand ~~stockholders~~Sunoco. As ~~agreement~~a ~~between~~result ~~ETE~~of ~~and~~this ~~ETP~~transaction, ETP ~~will~~now ~~control~~owns ~~Holdco.~~100% ~~This transaction did not result in a new basis~~ of ~~accounting for Southern Union~~Holdco.

11Discontinued 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. 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. All periods reflected herein have been restated to present the LDC Disposal Group’s operations as discontinued operations in the 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 31, 2013 and December 31, 2012.

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

The goodwill allocated to the LDC Disposal Group was $133 million at March 31, 2013.


4.	RELATED PARTY TRANSACTIONS:

~~The~~Accounts ~~following~~receivable ~~table~~from ~~provides~~related acompanies ~~summary~~reflected ofon the condensed consolidated balance sheets primarily related ~~party~~to ~~balances~~payroll ~~included~~funding inand ~~our~~various ~~condensed~~administrative ~~consolidated~~and ~~balance~~operating ~~sheets~~costs atpaid by the ~~dates~~Company ~~indicated:~~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.

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

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

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

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

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

	Successor
	Three Months Ended March 31, 2013
	Three months ended September 30, 2012			Period from Acquisition (March 26, 2012) to September 30, 2012
Operating revenues — ETP	$	20
Operating revenues — ETE	$	10,180		$	19,076
Cost of natural gas and other energy	13
Cost of natural gas and other energy	4,688			13,170
Operating, maintenance and general	25
Operating, maintenance and general	20,235			23,537
Earnings from unconsolidated investments	1
Interest expense	3,487			3,351
Losses from unconsolidated investments	(1,065		)	(381		)

5.The ~~COMPREHENSIVE~~Company ~~INCOME~~received ~~(LOSS):~~$2 million in distributions related to its investment in ETP during the three months ended March 31, 2013.

~~The tables below set forth the tax amounts included in the respective components of other comprehensive income (loss) for the periods presented:~~8

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

Table of Contents

125. ACCUMULATED OTHER COMPREHENSIVE LOSS:

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

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

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



	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	)

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


6.	DEBT OBLIGATIONS:

~~The~~Based ~~following~~on ~~table~~the ~~sets~~estimated ~~forth~~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 ~~Southern~~March 31, ~~Union~~2013 and ~~Panhandle~~December 31, at2012, the ~~dates~~aggregate ~~indicated:~~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.

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

Credit Facilities. The Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) provides for borrowings of up to $700 million and expires in May 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes. The annualized interest rate for the Southern Union Credit Facility was 1.83% as of March 31, 2013.

~~(1)~~As ~~Effective~~of ~~November 1~~March 31, ~~2011,~~2013 ~~the~~and ~~interest~~December 31, ~~rate~~2012, on the ~~Junior~~Company ~~Subordinated~~had ~~Notes~~$240 ~~changed~~million toand a$210 ~~variable~~million, ~~rate based upon the three-month LIBOR rate plus 3.0175%~~respectively, ~~reset~~outstanding ~~quarterly.~~under ~~See Interest Rate Swaps below for more information regarding~~ the ~~interest~~Southern ~~rate~~Union onCredit ~~these notes~~Facility.

~~(2)~~In ~~The~~connection ~~Southern~~with ~~Union~~the ~~Credit~~SUGS ~~Facility was included in short-term debt as of December 31~~Contribution, ~~2011,~~borrowings ~~but~~under ~~not~~the asSouthern ofUnion ~~September~~Credit ~~30,~~Facility ~~2012.~~were ~~See~~repaid ~~discussion~~and inthe ~~"Credit~~facility ~~Facilities" below~~terminated.

~~Based~~Panhandle onTerm ~~the~~Loans. The ~~estimated~~effective ~~borrowing~~interest ~~rates~~rate ~~currently available to the Company and its subsidiaries~~ for ~~loans with similar terms and average maturities,~~ the ~~aggregate~~$455 ~~fair~~million ~~value~~LNG ofHoldings ~~the~~term ~~Company's~~loan ~~consolidated~~due ~~debt~~February ~~obligations~~2015 ~~at September 30, 2012 and December 31, 2011~~ was $31.5583% ~~billion~~as ~~and $3.96 billion, respectively. As~~ of ~~September~~March ~~30, 2012 and December~~ 31, ~~2011, the aggregate carrying amount of the Company's consolidated debt obligations was $3~~2013.~~52 billion and $3.70 billion, respectively. The fair value of the Company's consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.~~

~~Credit~~Covenants ~~Facilities. In~~Related ~~March~~to ~~2012,~~Our ~~the Company entered into the Eighth Amended and Restated Revolving~~ Credit ~~Agreement~~Agreements. We ~~with~~were ~~certain banks~~ in ~~the~~compliance ~~amount~~with ofall ~~$700 million (Southern Union Credit Facility). The Southern Union Credit Facility is an amendment~~requirements, ~~restatement and refinancing of the Company’s $550 million Seventh Amended and Restated Revolving Credit Agreement. The Southern Union Credit Facility is scheduled to mature on May 20~~tests, ~~2016. The Company entered into the Southern Union Credit Facility in order to (i) obtain consent to the transactions contemplated by the Merger Agreement~~limitations, ~~the Citrus Merger Agreement~~ and ~~the~~covenants ~~Support~~related ~~Agreement; (ii)~~ to ~~increase~~our ~~the~~credit ~~amount~~agreements as of ~~the~~March 31, ~~facility from $550 million to $700 million; and (iii) to modify certain covenants~~2013. ~~Borrowings under the Southern Union Credit Facility are available for the~~

149

~~Company’s~~Table ~~working capital, other general corporate purposes and letter~~ of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes. The annualized interest rate for the Southern Union Credit Facility was 1.83% at September 30, 2012.Contents

~~On August 10, 2012, Southern Union entered into a First Amendment of the Southern Union Credit Facility~~7. ~~The~~RETIREMENT Amendment provides for, among other things, (i) a revision to the change of control definition to permit equity ownership of Southern Union by ETP or any direct or indirect subsidiaries of ETP in addition to ETE or any direct or indirect subsidiary of ETE; and (ii) a waiver of any potential default that may result from the Holdco Transaction.BENEFITS:

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

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

In February 2012, the Company refinanced LNG Holdings’ $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL’s senior unsecured debt.

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

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

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

7. BENEFITS:

Components of Net Periodic Benefit Cost

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

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

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

(1) Subsequent to the ETE Merger, the Company amended certain of its ~~other~~OPEB ~~postretirement employee benefit~~ plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, the Company recorded a pre-tax curtailment gain of $7475 million.6 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.

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

⁽²⁾

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

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8.	TAXES ON INCOME:

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

	Successor				~~Predecessor~~			Predecessor
	Three months ended September 30, 2012				Three months ended September 30, 2011
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
Current expense (benefit):
Total income tax expense (benefit) from continuing operations	$	10		$	(12	)		$	12
Federal	$	(419	)		$	(745	)
Effective tax rate	41		%	23		%		27		%
State	2,272				(143		)
Total	1,853				(888		)
Deferred expense:
Federal	25,742				21,903
State	1,364				3,431
Total	27,106				25,334
Total federal and state income tax expense	$	28,959			$	24,446
Effective tax rate	63		%		30		%

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

The Company’s effective income tax rate for the period ended March 31, 2013 was higher than the U.S. federal income tax statutory rate of 35% primarily due to state income taxes. During the period from March 26, 2012 to March 31, 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. During the period from January 1, 2012 to March 25, 2012, the effective income tax rate was lower than the federal statutory rate primarily as a result of the dividend received deduction for the anticipated receipt of dividends associated with the earnings from the Company’s prior unconsolidated investment in Citrus.

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


9.	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

The Company is exposed to certain risks in its ongoing business operations. The primary risks managed by using derivative instruments are interest rate risk and commodity price risk. Interest rate swaps ~~and treasury rate locks~~ are the principal derivative instruments used by the Company to manage interest rate risk associated with its long-term borrowings, although other interest rate derivative contracts may also be used from time to time. Natural gas and NGL price swaps ~~as well as call options~~ and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time. The Company recognizes all derivative instruments as assets or liabilities at fair value in the consolidated balance sheets.

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

Interest Rate Contracts

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

Interest Rate Swaps. In 2011, the Company entered into interest rate swap agreements to hedge the $600 million Junior Subordinated Notes due 2066 with an aggregate notional amount of $525 million, of which $450 million were for ten-year periods and $75 million were for five-year periods. These interest rate swaps became effective on November 1, 2011. The Company pays interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175% beginning November 1, 2011. The interest rate swaps effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notes and are accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings. The floating rate LIBOR-based portion of the interest payments was exchanged for weighted average fixed rate interest payments of 3.63%. In conjunction with the ETE Merger, the Company discontinued hedge accounting treatment on these interest rate swaps. Therefore, ~~future~~ changes in fair value ~~will~~were be recognized in earnings.

The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012. These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified 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.

Treasury Rate Locks. As of September 30, 2012, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt. During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in accumulated other comprehensive income and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.11

Table of Contents

Commodity Contracts – Gathering and Processing Segment

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

Natural Gas Price Swaps. As of ~~September~~March 3031, ~~2012~~2013, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 23,~~760~~437,~~000 MMBtu for the remainder of 2012 and 10,037,~~500 MMBtu for 2013. These natural gas price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in accumulated other comprehensive income and reclassified into operating revenues in the same periods during which the forecasted natural gas sales impact earnings. As of ~~September~~March 3031, ~~2012~~2013, approximately $~~0.7~~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 ~~twelve~~12 months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

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

18Through the Distribution segment, included in the LDC Disposal Group at March 31, 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.

~~swaps~~Natural ~~are~~Gas ~~accounted~~Price ~~for~~Swaps. As asof ~~cash~~March 31, ~~flow hedges~~2013, ~~with~~ the ~~effective~~Company ~~portion~~had ofoutstanding ~~changes~~pay-fixed innatural ~~their~~gas ~~fair~~price ~~value~~swaps ~~recorded~~with intotal ~~accumulated~~notional ~~other~~amounts ~~comprehensive~~of ~~income~~14,030,000 ~~and~~MMBtu, ~~reclassified~~8,160,000 ~~into~~MMBtu ~~operating~~and ~~revenues~~220,000 inMMBtu ~~the~~for ~~same periods during which~~ the ~~forecasted~~remainder ~~NGL sales impact earnings. As~~ of ~~September 30~~2013, ~~2012,~~2014 ~~approximately~~and $62015, respectively.1 These ~~million~~natural ofgas ~~net after-tax losses in accumulated other comprehensive income related to these NGL~~ price swaps are ~~expected~~accounted tofor beas ~~recognized~~economic inhedges, ~~operating~~with ~~revenues~~changes ~~during~~in ~~the~~their ~~next~~fair 12value ~~months. Any~~recorded ~~ineffective~~to ~~portion~~deferred ofnatural ~~the~~gas ~~cash flow hedge is reported in current-period earnings~~purchases.

Commodity Contracts - Distribution Segment

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

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

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the ~~unaudited interim condensed~~ consolidated balance sheets at the dates indicated:. The asset and liability derivative instruments belonging to the Distribution segment have been included in current asset and liabilities held for sale at March 31, 2013.

	Fair Value
	Asset Derivatives					Liability Derivatives	~~Liability Derivatives~~
	Successor			Predecessor			Successor				Predecessor
Balance Sheet Location	March 31, 2013		December 31, 2012			March 31, 2013			December 31, 2012
Balance Sheet Location	September 30, 2012			December 31, 2011			September 30, 2012				December 31, 2011
Cash Flow Hedges:
Cash Flow Hedges:
Commodity contracts — Gathering and Processing:
Interest rate contracts:
Natural gas price swaps:
Derivative instruments — liabilities	$	—		$	—		$	—			$	19,936
Accounts payable to related companies	$	—	$	—		$	3		$	5
Deferred credits	—			—			—				59,789
	—		—			3			5
Commodity contracts — Gathering and Processing:
Economic Hedges:
Natural gas price swaps
Interest rate contracts:
Prepayments and other assets	1,498			6,124			—				—
Derivative instruments — liabilities	—		—			18			18
Accounts payable — related parties	—			—			7,135				—
Deferred credits	—		—			54			59
NGL price swaps
Commodity contracts — Distribution:
Prepayments and other assets	4,323			—			—				1,996
Natural gas price swaps:
Derivative instruments — liabilities	—			—			—				4,144
Current assets held for sale	8		1			—			—
	$	5,821		$	6,124		$	7,135			$	85,865
Non-current assets held for sale	—		1			—			—
Economic Hedges:
Current liabilities held for sale	—		—			2			9
Interest rate contracts:
	8		2			74			86
Derivative instruments — liabilities	$	—		$	—		$	17,310			$	—
Total	$	8	$	2		$	77		$	91
Deferred credits	—			—			63,142				—
Commodity contracts — Gathering and Processing:
Other derivative instruments
Derivative instruments — liabilities	—			—			—				50
Commodity contracts — Distribution:
Natural gas price swaps
Other non-current assets	768			—			—				—
Derivative instruments — liabilities	—			—			7,958				34,468
Deferred credits	—			3			—				5,643
	$	768		$	3		$	88,410			$	40,161
Total	$	6,589		$	6,127		$	95,545			$	126,026

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

2012

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

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

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

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

Derivative Instrument Contingent Features

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

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10.	FAIR VALUE MEASUREMENT:

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

Fair Value Measurements at September 30, 2012

Fair Valueas of

Fair Value Measurements at March 31, 2013Using Fair Value Hierarchy

Fair Value Total

Level 1

Level 2

Level 3

March 31, 2013

Level 1

Level 2

Level 3

Assets:

Commodity derivatives

6~~,589~~

—

6~~,589~~

—

Total

6~~,589~~

—

6~~,589~~

—

Liabilities:

Commodity derivatives

~~15,093~~3

—

~~15,093~~3

—

Interest-rate swap derivatives

~~80,452~~72

—

~~80,452~~72

—

Total

~~95,545~~75

—

~~95,545~~75

—

The Company’s Level 2 instruments primarily include natural gas and NGL price swaps and NGL processing spread swap derivatives and interest-rate swap derivatives that are valued using pricing models based on an income approach that discounts future cash flows to a present value amount. The significant pricing model inputs for natural gas and NGL price swaps and NGL processing spread swap derivatives include published NYMEX forward index prices for delivery of natural gas at Henry Hub, Permian Basin and Waha, and NGL at Mont Belvieu. The significant pricing model inputs for interest-rate swaps include published rates for U.S. Dollar LIBOR interest rate swaps. The pricing models also adjust for nonperformance risk associated with the counterparty or ~~the~~ Company, as applicable, through the use of credit risk adjusted discount rates based on published default rates. The Company did not have any Level 3 instruments measured at fair value at ~~September~~March ~~30, 2012 or December~~ 31, ~~2011~~2013 and there were no transfers between hierarchy levels.

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


11.	COMMITMENTS AND CONTINGENCIES:

PEPL Holdings Guarantee of Collection

In accordance with the Contribution Agreement pursuant to which the Company contributed SUGS to Regency, 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. In connection with the closing of the SUGS contribution, on April 30, 2013, Regency entered into the guarantee 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.

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.

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

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

Gathering and Processing Segment

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

Distribution Segment

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

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

2315

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

Environmental Remediation Liabilities

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

	Successor			Predecessor
	March 31, 2013		December 31, 2012
	September 30, 2012			December 31, 2011
Current	$	7	$	7
Current	$	4,363		$	9,353
Noncurrent	26		26
Noncurrent	24,588			11,635
Total environmental liabilities	$	33	$	33
Total environmental liabilities	$	28,951		$	20,988

Litigation and Other Claims

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

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with the Company’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling $~~18.5~~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 ~~COO~~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.

~~Air~~Litigation ~~Quality~~Relating ~~Control. SUGS is currently negotiating settlements~~ to ~~certain enforcement actions by~~ the ~~NMED~~ETE ~~and the TCEQ.~~Merger

24In 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,

~~Compliance Orders from the New Mexico Environmental Department~~16

~~SUGS~~Table ~~has been in discussions with the NMED concerning allegations~~ of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The NMED has issued amended compliance orders (COs) and proposed penalties for alleged violations at Jal #4 in the amount of $0.5 million and at Jal #3 in the amount of $5.5 million. Hearings on the COs were delayed to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Company has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.Contents

~~Litigation~~2011, ~~Relating~~the court denied ETE's October 13, 2011, motion to stay the ~~Merger~~Texas ~~with~~proceeding ~~ETE~~in favor of cases pending in the Delaware Court of Chancery.

OnAlso in June ~~21,~~ 2011, aseveral putative class action ~~lawsuit~~lawsuits ~~captioned~~were ~~Jaroslawicz~~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., ~~Cause~~C.A. No. ~~2011~~6615-~~37091,~~CS; ~~was~~KBC ~~filed~~Asset inManagement ~~the~~NV ~~333rd~~v. ~~Judicial~~Southern ~~District~~Union ~~Court~~Company, ofet ~~Harris County~~al., ~~Texas~~C. ~~The~~A. ~~petition~~No. ~~named~~6622-CS; asLBBW ~~defendants~~Asset ~~the~~Management ~~members~~Investment ofGmbH ~~the~~v. Southern Union ~~Board~~Company, aset ~~well~~al., asC.A. ~~Southern~~No. ~~Union~~6627-CS; and ~~ETE~~Memo v. ~~The~~ ~~plaintiff~~Southern ~~alleged~~Union ~~that~~Company, ~~the~~et ~~defendants~~al., ~~breached~~C.A. ~~their~~No. ~~fiduciary~~6639-CS. These ~~duties~~cases towere ~~Southern~~consolidated ~~Union’s~~with ~~stockholders~~the orfollowing ~~aided~~style: In ~~and~~re ~~abetted~~Southern ~~breaches~~Union ofCo. ~~fiduciary~~Shareholder ~~duties~~Litigation, inC.A. ~~connection~~No. ~~with~~6615-CS, in the ~~Merger~~Delaware Court of Chancery. The ~~petition~~consolidated ~~alleged~~complaint ~~that~~asserts similar claims and allegations as the ~~Merger~~Texas ~~involves~~state-court anconsolidated ~~unfair~~action. On ~~price~~July ~~and~~25, an2012, ~~inadequate~~the ~~sales~~Delaware ~~process~~plaintiffs ~~and~~filed ~~that~~a ~~defendants~~notice ~~entered~~of ~~into~~voluntary ~~the~~dismissal ~~transaction~~of toall ~~benefit~~claims ~~themselves~~without ~~personally~~prejudice. ~~The~~ In ~~petition~~the ~~sought~~notice, ~~injunctive~~plaintiffs ~~relief,~~stated ~~including~~their anclaims ~~injunction~~were ofbeing ~~the~~dismissed ~~Merger,~~to ~~attorneys’~~avoid duplicative litigation and ~~other~~indicated ~~fees~~their ~~and~~intent ~~costs,~~to ~~indemnification~~join ~~and~~the ~~other~~Texas ~~relief~~case.

~~Also~~The ~~on June 21, 2011, another putative class action lawsuit captioned Magda v. Southern Union Company, et al., Cause No. 2011-37134, was filed in the 11th Judicial District Court of Harris County,~~ Texas~~. The~~ ~~petition~~case ~~named~~remains ~~as defendants the members of the Southern Union Board~~pending, ~~Southern Union,~~ and ~~ETE. The~~discovery ~~plaintiff~~is alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted those alleged breachesongoing. The petition alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The petition sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

OnIn ~~June~~November ~~28,~~ 2011, ~~and~~a ~~August~~derivative ~~19,~~lawsuit ~~2011,~~was ~~amended petitions were~~ filed in the ~~Magda~~Judicial ~~and~~District ~~Jaroslawicz~~Court ~~actions,~~of ~~respectively~~Harris County, Texas naming ~~the~~as ~~same~~ defendants ~~and~~ETP, ~~alleging~~ETP ~~that~~GP, ETP LLC, the ~~Southern~~boards ~~Union~~of directors ~~breached~~of ~~their~~ETP ~~fiduciary~~LLC ~~duties~~(collectively towith ~~Southern~~ETP ~~Union’s~~GP ~~stockholders~~and inETP ~~connection~~LLC, ~~with~~ the ~~Merger~~“ETP ~~and~~Defendants”), ~~that~~certain ~~Southern~~members ~~Union~~of management for ETP and ETE, ~~aided~~ETE, and ~~abetted~~Southern ~~the~~Union. The ~~alleged~~lawsuit ~~breaches~~is ofstyled ~~fiduciary~~W. ~~duty~~J. ~~The~~ ~~amended~~Garrett ~~petitions~~Trust ~~allege~~v. ~~that~~Bill ~~the~~W. ~~Merger~~Byrne, ~~involves~~et anal., ~~unfair~~Cause ~~price~~No. ~~and~~2011-71702, anin ~~inadequate~~the ~~sales~~157th ~~process,~~Judicial ~~that~~District ~~Southern~~Court ~~Union’s~~of ~~directors~~Harris ~~entered~~County, ~~into~~Texas. Plaintiffs ~~the~~assert ~~Merger~~claims tofor ~~benefit~~breaches ~~themselves~~of ~~personally~~fiduciary duty, ~~including~~breaches ~~through~~of ~~consulting~~contractual duties, and ~~noncompete~~acts ~~agreements,~~of bad faith against each of the ETP Defendants and ~~that~~the individual defendants. Plaintiffs ~~have~~also ~~failed~~assert toclaims ~~disclose~~for ~~all~~aiding ~~material~~and ~~information~~abetting ~~related~~and totortious ~~the~~interference ~~Merger~~with tocontract against Southern Union ~~stockholders~~. ~~The~~On ~~amended~~October ~~petitions~~5, ~~seek~~2012, ~~injunctive~~certain ~~relief,~~defendants ~~including~~filed ana ~~injunction~~motion offor ~~the~~summary ~~Merger,~~judgment ~~and~~with anrespect ~~award~~to ofthe ~~attorneys’~~primary ~~and~~allegations ~~other~~in ~~fees~~this ~~and~~action. On ~~costs~~December 13, in2012, ~~addition~~Plaintiffs tofiled ~~other~~their ~~relief. The~~opposition ~~two~~to ~~Texas~~the ~~cases~~motion ~~have~~for ~~been~~summary ~~consolidated~~judgment. Defendants ~~with~~filed ~~the~~a ~~following~~reply ~~style:~~on InDecember ~~re:~~19, 2012. ~~Southern~~On ~~Union~~December ~~Company;~~20, ~~Cause~~2012, ~~No.~~the ~~2011-37091,~~court inconducted an oral hearing on the ~~333rd~~motion. Plaintiffs ~~Judicial~~filed ~~District~~a ~~Court~~post-hearing ofsur-reply ~~Harris~~on ~~County~~January 7, ~~Texas~~2013. On ~~October~~January 2116, ~~2011~~2013, the ~~court~~Court ~~denied~~granted ~~ETE’s~~defendants' ~~October~~motion ~~13,~~for ~~2011~~summary ~~motion~~judgment. The todeadline ~~stay~~for the ~~Texas~~remaining ~~proceeding~~defendants into ~~favor~~file ofan ~~cases~~answer ~~pending~~or inotherwise ~~the~~respond ~~Delaware~~is ~~Court~~late ofApril, ~~Chancery~~2013. Trial ~~(described~~in ~~below)~~this action is not currently set.

On June 27, 2011, a putative class action lawsuit captioned Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS, was filed in the Delaware Court of Chancery. The complaint named as defendants the members of the Southern Union Board, Southern Union and ETE. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and further claimed that ETE aided and abetted those alleged breaches. The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors should deem a competing proposal made by The Williams Companies, Inc. (Williams) to be superior. The complaint sought compensatory damages, injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On June 29 and 30, 2011, putative class action lawsuits captioned KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS, and LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS, respectively were filed in the Delaware Court of Chancery. The complaints named as defendants the members of the Southern Union Board, Southern Union, ETE and Merger Sub. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that ETE aided and abetted those alleged breaches. The complaints alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the directors must give full consideration to the Williams proposal. The complaints sought

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

On July 6, 2011, a putative class action lawsuit captioned Memo v. Southern Union Company, et al., C.A. No. 6639-CS, was filed in the Delaware Court of Chancery. The complaint named as defendants the members of the Southern Union Board, Southern Union ETE and Merger Sub. The plaintiffs alleged that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the amended Merger agreement and that Southern Union, ETE and Merger Sub aided and abetted those alleged breaches. The complaint alleged that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, and that the terms of the amended Merger agreement are preclusive. The complaint sought injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

On August 25, 2011, a consolidated amended complaint was filed in the Southeastern Pennsylvania Transportation Authority, KBC Asset Management NV, and LBBW Asset Management Investment GmbH actions pending in the Delaware Court of Chancery naming the same defendants as the original complaints in those actions and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger, that ETE aided and abetted those alleged breaches of fiduciary duty, and that the provisions in Section 5.4 of the Second Amended Merger Agreement relating to Southern Union’s ability to accept a superior proposal is invalid under Delaware law. The amended complaint alleges that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that the defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.

The consolidated amended complaint seeks injunctive relief, including an injunction of the Merger and an award of attorneys’ and other fees and costs, in addition to other relief.

The four Delaware Court of Chancery cases have been consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery.

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

On July 25, 2012, the plaintiffs in the Delaware action filed a notice of voluntary dismissal of all claims without prejudice with the Delaware Court of Chancery. In the notice, the plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case before the District Court of Harris County, Texas, 333rd Judicial District, captioned In re Southern Union Company, and docketed at Cause No. 2011-37091.

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

In November 2011, a derivative lawsuit captioned W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, was filed in the 234th Judicial District Court of Harris County, Texas. The petition stated that it was filed on behalf of ETP. ETP was also named as a nominal defendant. The petition also named as defendants Energy Transfer Partners, GP, L.P. (ETP GP), Energy Transfer Partners, LLC (ETP LLC), the Boards of Directors of ETP LLC (collectively with ETP GP, and ETP LLC, the ETP Defendants), ETE, and Southern Union. In October 2012, the plaintiff and two new unitholder plaintiffs filed their Third Amended Petition, naming these same defendants and adding Royal Bank of Scotland, PLC, RBS Securities, Inc. (RBS), and four members of ETP management (Management Defendants) as defendants. In their third amended petition, the plaintiffs allege that the ETP Defendants breached their fiduciary and contractual duties in connection with the Citrus Merger and ETP’s contribution of its propane assets to AmeriGas Partners, L.P. (the AmeriGas Transaction). The third amended petition alleges that the Citrus Merger, among other things, involves an unfair price and an unfair process and that the ETP Defendants failed to adequately evaluate the transaction. The third amended petition also alleges that the ETP Defendants failed to, among other things, adequately evaluate the AmeriGas Transaction. The third amended petition alleges that these defendants entered into both transactions primarily to assist in ETE’s consummation of its merger with Southern Union and thereby primarily to benefit themselves personally. The third amended petition further alleges that RBS committed malpractice in issuing fairness opinions and that the Management Defendants failed to disclose material information regarding RBS' relationship with ETE. The third amended petition asserts claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and Management Defendants. The third amended petition asserts claims against ETE and Southern Union for aiding and abetting the breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith, as well as tortious interference with contract. The third amended petition also asserts claims for declaratory judgment and

conspiracy against all defendants. The lawsuit seeks, among other things, the following relief: (i) a declaration that the lawsuit is properly maintainable as a derivative action; (ii) a declaration that the Citrus Merger and AmeriGas Transaction were unlawful and unenforceable because they involved breaches of fiduciary and contractual duties; (iii) a declaration that ETE and Southern Union aided and abetted the alleged breaches of fiduciary and contractual duties; (iv) a declaration that defendants conspired to breach, aided and abetted, and did breach fiduciary and contractual duties; (v) an order directing the ETP Defendants and Management Defendants to exercise their fiduciary duties to obtain a transaction or transactions in the best interest of ETP’s unitholders; (vi) damages; and (vii) attorneys’ and other fees and costs.

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

Mercury Release

In October 2004, New England Gas Company discovered that one of its facilities, formerly associated with discontinued operations which were sold in 2006, had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island (“District Court”) alleging violation of permitting requirements under the ~~federal~~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 ~~has~~ petitioned the District Court for ~~consideration of the same issues with the hearing scheduled for December 3, 2012. A ruling against the Company would likely result in a judgment of up to approximately $750,000.~~

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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.

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 ~~September~~March 3031, ~~2012~~2013 and December 31, ~~2011~~2012, the Company recorded litigation and other claim-related accrued liabilities of $~~9.3~~27 million and $~~28.3~~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 13 for potential contingent matters associated with the Company’s regulated operations.

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

Air Quality Control

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

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

Nitrogen oxides are the primary air pollutant from natural gas-fired engines. Nitrogen oxide emissions may form ozone in the atmosphere. In 2008, the EPA lowered the ozone standard to 75 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.~~

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dioxide non-attainment areas. In addition, ambient air quality modeling may be required to demonstrate compliance with the new standard.

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

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

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

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


12.	REPORTABLE SEGMENTS:

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

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

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. There were no material intersegment revenues during the ~~nine~~three months ended March ~~September~~31, 302013, the period from Acquisition (March 26, 2012) to March 31, 2012 and ~~2011~~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 unallocated corporate costs, a wholly-owned subsidiary with ownership interests in electric power plants, and other miscellaneous activities.

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

29Segment Adjusted EBITDA may not be comparable to measures used by other companies and should be considered in conjunction with net earnings and other performance measures such as operating income or net cash flows provided by operating activities.

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

	Successor			~~Predecessor~~		Predecessor
	Three months ended September 30, 2012			Three months ended September 30, 2011
	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	$	~~188,481~~199	$	$13	~~192,699~~	$	194
Gathering and Processing	~~213,382~~190		20	~~339,658~~		246
Distribution	73,237			80,763
Total segment operating revenues	389		33			440
Total segment operating revenues	475,100			613,120
Corporate and other activities	4		(2		)	3
Corporate and other activities	2,796			4,091
	$	393	$	31		$	443
	$	477,896		$	617,211
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

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

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

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

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	Successor				~~Predecessor~~			Predecessor
	Period from Acquisition (March 26, 2012) to September 30, 2012				Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
	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:
Transportation and Storage	$	~~205,130~~124		$	$(33	~~185,706~~)		$	~~570,072~~186
Gathering and Processing	~~36,155~~(6		)	(11	~~25,338~~	)		~~94,440~~25
Distribution	~~35,907~~39			(10	~~33,554~~	)		~~58,673~~34
Corporate and other activities	~~(2,471~~4		)	(2	~~(18,845~~	)	)	(7019		)
Total Segment Adjusted EBITDA	~~274,721~~161			(56	~~225,753~~	)		~~723,115~~226
Depreciation and amortization	(~~154,909~~59		)	(4	~~(56,544~~	)	)	(~~177,949~~49		)
Unrealized losses on unhedged derivative activities	—				—			(9,283		)
Net gain on curtailment of OPEB plans	—			15				—
Net gain on curtailment of OPEB plans	15,332				—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(2		)	—				(1		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(12,116		)		(1,350		)	(7,580		)
Other, net	1			—				(2		)
Other, net	(564		)		284			557
Earnings from unconsolidated investments	1			—				16
Earnings (losses) from unconsolidated investments	(381		)		16,160			78,435
Adjusted EBITDA attributable to unconsolidated investments	(5		)	—				(61		)
Adjusted EBITDA attributable to unconsolidated investments	(7,673		)		(61,108		)	(194,723		)
Adjusted EBITDA attributable to discontinued operations	(40		)	(3		)		(34		)
Interest expense	(~~96,323~~33		)	(4	~~(50,407~~	)	)	(~~165,429~~50		)
Income before income tax expense	18,087				72,788			247,143
Income (loss) from continuing operations before income tax expense	$	24		$	(52	)		$	45
Income tax expense	(27,883		)		(22,871		)	(68,676		)
Net income (loss)	$	(9,796	)		$	49,917		$	178,467

	Successor			Predecessor
	March 31, 2013		December 31, 2012
	September 30, 2012			December 31, 2011
Total assets:
Total assets:
Transportation and Storage	$	6,198	$	6,219
Transportation and Storage	$	5,695,305		$	5,288,967
Gathering and Processing	2,038		1,965
Gathering and Processing	2,820,127			1,742,516
Distribution (1)	1,224		1,190
Distribution	1,249,047			1,075,253
Total segment assets	9,460		9,374
Total segment assets	9,764,479			8,106,736
Corporate and other activities	686		619
Corporate and other activities	115,333			164,123
Total assets	$	10,146	$	9,993
Total assets	$	9,879,812		$	8,270,859

(1)Distribution segment assets have been reported as assets held for sale in the consolidated balance sheets at March 31, 2013 and December 31, 2012.


13.	REGULATION AND RATES:

Panhandle. InOn ~~October~~July ~~2011~~26, 2012, Trunkline ~~and~~filed ~~Sea~~an ~~Robin~~application ~~jointly filed~~ with the FERC for approval to transfer ~~all~~approximately of770 ~~Trunkline's~~miles ~~offshore~~of ~~facilities,~~underutilized ~~and~~loop ~~certain~~piping ~~related onshore~~ facilities, by sale ~~and transfer~~ to ~~Sea~~an ~~Robin~~affiliate; tosuch ~~consolidate~~facilities ~~and~~are ~~streamline~~contemplated ~~the~~to ~~ownership~~be ~~and~~converted ~~operation~~to ofcrude ~~all~~oil ~~regulated~~transportation ~~offshore~~service. This ~~assets~~sale ~~under~~is ~~one~~subject ~~entity~~to ~~and~~FERC ~~better position the offshore assets competitively~~approval. Several parties ~~filed~~have ~~interventions~~intervened, ~~and~~commented, ~~protests~~or ofprotested this filing~~. On~~ ~~June 21, 2012, FERC issued an order granting Trunkline permission~~ and ~~approval~~the toCompany ~~proceed~~is ~~with~~currently ~~the~~responding ~~transfer, subject~~ to ~~compliance with certain regulatory requirements. On July 31, 2012 Sea Robin and Trunkline made~~ the ~~necessary~~Commission’s ~~compliance~~requests ~~filings~~for ~~with~~additional ~~FERC. The~~information ~~transfer~~on ~~of the offshore facilities to Sea Robin was completed in the third quarter of~~ this ~~year~~application.

OnIn ~~July~~November 262011, ~~2012,~~the ~~Trunkline~~FERC ~~filed~~commenced an ~~application~~audit ~~with~~of ~~the~~PEPL ~~FERC~~to ~~for~~evaluate ~~approval~~its tocompliance ~~transfer~~with ~~approximately~~the ~~770~~Uniform ~~miles~~System of ~~underutilized~~Accounts ~~loop~~as ~~piping~~prescribed ~~facilities~~ by ~~sale~~the toFERC, anannual ~~affiliate.~~and ~~This~~quarterly ~~sale~~financial isreporting ~~subject~~ to the FERC, ~~approval.~~reservation ~~These~~charge ~~facilities~~crediting ~~would~~policy beand ~~converted~~record toretention. The aaudit ~~crude~~is ~~oil~~related ~~transportation~~to ~~service.~~the ~~Several~~period ~~parties~~from ~~have~~January ~~intervened~~1, ~~commented,~~2010 orthrough ~~protested~~December ~~this~~31, ~~filing~~2011 and ~~the Company~~ is ~~currently~~pending ~~responding to~~ the ~~Commission's~~issuance ~~requests~~of ~~for~~a ~~additional~~draft ~~information~~audit ~~on this application~~report.

InNew ~~November~~England ~~2011,~~Gas ~~FERC~~Company. On ~~commenced~~September an15, ~~audit~~2008, ofNew ~~PEPL~~England toGas ~~evaluate~~Company ~~its~~made ~~compliance~~a filing with the ~~Uniform~~MDPU ~~System~~seeking recovery of ~~Accounts~~approximately as$4 ~~prescribed~~million, byor ~~FERC,~~50% ~~annual~~of ~~and~~the ~~quarterly~~amount ~~financial~~by ~~reporting~~which toits ~~FERC,~~2007 ~~reservation~~earnings ~~charge~~fell ~~crediting~~below ~~policy~~a ~~and~~return ~~record~~on ~~retention~~equity of 7%. ~~The~~This ~~audit~~filing iswas ~~related~~made pursuant to New England Gas Company’s rate settlement approved by the ~~period~~MDPU ~~from~~in ~~January~~2007. On 1February 2, ~~2010~~2009, ~~through~~the ~~December~~MDPU ~~31,~~issued ~~2011~~its ~~and~~order isdenying ~~currently~~the ~~still~~Company’s requested earnings sharing adjustments (“ESA”) in ~~progress~~its entirety. The Company appealed that decision to the Massachusetts Supreme Judicial Court (“MSJC”). On November 13,

3121

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

New England Gas Company. On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50% of the amount by which its 2007 earnings fell below a return on equity of 7%. This filing was made pursuant to New England Gas Company’s rate settlement approved by the MDPU in 2007. On February 2, 2009, the MDPU issued its order denying the Company’s requested earnings sharing adjustments (ESA) in its entirety. The Company appealed that decision to the Massachusetts Supreme Judicial Court (MSJC). On November 13, 2009, New England Gas Company made a similar filing with the MDPU, also pursuant to the above-referenced settlement, to recover approximately $~~1.7~~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 $4.1 million is the appropriate ESA amount for recovery related to calendar year 2007 and that such amount should be recovered over a twelve month period beginning November 1, 2011; and (ii) investigate New England Gas Company’s request for recovery of an ESA amount of $~~1.7~~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. ~~The~~On January 25, 2013, the MDPU issued its order approving the 2008 ESA isfor ~~awaiting~~$2 ~~further~~million ~~action~~to bybe recovered over a twelve-month period beginning February 1, 2013, which reflected a reduction of approximately $10,000 from the ~~MDPU~~initial request.

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

AND RESULTS OF OPERATIONS

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

~~INTRODUCTION~~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.

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

~~RESULTS OF OPERATIONS~~OVERVIEW

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

The ~~Company~~ETE ~~evaluates~~Merger, ~~operational~~which ~~and~~was ~~financial~~completed ~~segment~~on ~~performance~~March 26, 2012, was accounted for by ETE using ~~several~~business ~~factors,~~combination accounting. By the application of ~~which~~“push-down” accounting, the ~~primary~~Company ~~financial~~allocated ~~measure~~the ispurchase ~~Segment~~price ~~Adjusted~~paid ~~EBITDA~~by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates. ~~For~~Accordingly, ~~additional~~the ~~information~~successor ~~related~~financial tostatements ~~the~~reflect ~~Company’s~~a ~~use~~new basis of ~~Segment~~accounting ~~Adjusted~~and ~~EBITDA~~predecessor asand ~~its~~successor ~~primary~~period financial ~~measure~~results ~~for~~(separated ~~its~~by ~~reportable~~a ~~segments~~heavy black line) are presented, ~~see~~but ~~Note~~are 12not comparable.

The ~~Merger,~~most ~~which~~significant ~~was~~impacts ~~completed~~of onthe ~~March~~new ~~26,~~basis ~~2012,~~of ~~was~~accounting ~~accounted~~going ~~for~~forward byare ~~ETE~~expected ~~using~~to ~~business~~be ~~combination~~(i) ~~accounting. By~~higher ~~the~~depreciation ~~application~~expense ofdue ~~"push~~to the step-~~down"~~up ~~accounting,~~of ~~the~~depreciable ~~Company~~assets ~~allocated~~and ~~the~~assignment of purchase price ~~paid~~to bycertain ~~ETE~~amortizable tointangible ~~its~~ assets, ~~liabilities~~ and ~~equity~~(ii) aslower ofinterest ~~the~~expense ~~acquisition~~(though ~~date~~not ~~based~~cash onpayments) ~~preliminary~~for ~~estimates. Accordingly,~~ the ~~successor~~remaining ~~financial~~life ~~statements~~of ~~reflect~~the arelated ~~new~~long-term ~~basis~~debt ofdue ~~accounting~~to ~~and~~its ~~predecessor~~revaluation and ~~successor~~related ~~period~~debt ~~financial~~premium ~~results (separated by a heavy black line) are presented, but are not comparable~~amortization.

32The 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 ~~most~~Company ~~significant~~reports ~~impacts~~Segment ofAdjusted ~~the~~EBITDA ~~new~~as ~~basis~~a measure of ~~accounting~~segment ~~during~~performance. The ~~the~~Company ~~successor~~defines ~~periods~~Segment ~~were~~Adjusted ~~(i)~~EBITDA ~~higher~~as earnings before interest, taxes, depreciation, ~~expense~~amortization ~~due~~and toother ~~the~~non-cash ~~step~~items, such as non-upcash ofcompensation ~~depreciable~~expense, ~~assets~~unrealized gains and ~~assignment~~losses ofon ~~purchase~~unhedged ~~price~~derivative toactivities, ~~certain~~accretion ~~amortizable~~expense ~~intangible~~and amortization of regulatory assets and ~~(ii)~~other ~~lower~~non-operating ~~interest~~income or expense ~~(though~~items. Adjusted ~~not~~EBITDA ~~cash~~reflects ~~payments)~~amounts for ~~the~~unconsolidated ~~remaining~~affiliates ~~life~~based ofon the ~~related~~Company's ~~long-term~~proportionate ~~debt~~ownership ~~due~~and toamounts ~~its~~for ~~revaluation~~less ~~and~~than ~~related~~wholly ~~debt~~owned ~~premium~~subsidiaries ~~amortization~~based on 100% of the subsidiaries' results of operations.

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

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

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

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

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

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

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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.

Holdco Transaction

On April 30, 2013, ETP acquired from ETE its 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.

RESULTS OF OPERATIONS

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



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

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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:

33• 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.

• ~~Incremental~~The ~~depreciation~~application ~~and~~of ~~amortization~~“push-down” ~~expense~~accounting ofalso ~~approximately~~resulted ~~$13.2~~in ~~million~~the ~~per~~Company’s ~~quarter~~long-term ~~has~~debt ~~been~~being ~~recognized~~recorded inat ~~the~~fair ~~successor~~value, ~~periods~~which ~~subsequent~~impacted tothe ~~March~~amount ~~25,~~of ~~2012~~amortization asrecorded ain ~~result~~interest ofexpense. This change in the ~~application~~amount of ~~the~~amortization ~~new~~resulted ~~basis~~in a net reduction within interest expense of ~~accounting~~approximately $10 million per quarter subsequent to March 25, 2012.

• ~~The~~In ~~application~~addition ofto ~~“push-down”~~the ~~accounting~~impact ~~also~~of ~~resulted in~~ the ~~Company's~~amortization ~~long-term~~of the debt ~~being recorded at~~ fair value adjustments, ~~which impacted the amount of amortization recorded in~~ interest expense. ~~This~~was ~~change~~also inlower during the ~~amount~~three ofmonths ~~amortization~~ended ~~resulted~~March in31, a2013 ~~net~~due ~~reduction~~to ~~within~~repayments ~~interest expense~~ of ~~approximately~~long-term ~~$9.6~~debt ~~million~~in ~~per quarter for period subsequent to March 25,~~ 2012.

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

The “Supplemental Pro Forma Information” section, which follows the “Business Segment Results” section, provides additional analysis of the Company'’s consolidated net income on a year-to-date basis, assuming the ETE Merger had been completed on January 1, ~~2011~~2012.

Federal and State Income Taxes

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

	Successor				~~Predecessor~~			~~Successor~~Predecessor			~~Predecessor~~
	Three months ended September 30, 2012				Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
	Three Months EndedMarch 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012				Period from January 1, 2012 to March 25, 2012
Income tax expense	$	28,959			$	24,446		$	27,883		$	22,871		$	68,676
Income tax expense (benefit)	$	10		$	(12	)		$	12
Effective tax rate	6341		%	23	30	%	%	~~154~~27		%	31		%	28		%

The ~~increases~~Company’s effective income tax rate for the period ended March 31, 2013 was higher than the federal statutory rate of 35% primarily due to state income taxes. The effective income tax rate for the period from March 26, 2012 to March 31, 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 ~~during~~for the ~~successor~~period ~~periods~~from ~~are~~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.

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

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

Business Segment Results

Transportation and Storage Segment

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest, ~~and from the~~ Gulf Coast toand ~~Florida~~Midcontinent United States, and LNG terminalling and regasification services. The Transportation and Storage segment’s operations, ~~conducted through Panhandle and, through March 26, 2012 (the date of the Citrus Merger), Florida Gas,~~ are regulated as to rates and other matters by 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. Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads. See Note 3 for information related to the Citrus Merger.

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

3424

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

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.

	Successor				~~Predecessor~~			~~Successor~~Predecessor			~~Predecessor~~
	Three months ended September 30, 2012				Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
	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)	$	~~188,481~~199		$	$13	~~192,699~~		$	~~387,173~~194		$	~~193,921~~		$	~~584,753~~
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(~~60,181~~67		)	(46	~~(63,421~~	)	)	(~~170,015~~60		)	~~(60,402~~		)	~~(181,614~~		)
Taxes other than on income and revenues	(~~9,189~~8		)	—	~~(8,653~~		)	(~~18,979~~9		)	~~(8,801~~		)	~~(26,392~~		)
Adjusted EBITDA attributable to unconsolidated investments	3,375				79,327			6,951			60,988			193,325
Adjusted EBITDA related to unconsolidated investments	—			—				61
Segment Adjusted EBITDA	$	~~122,486~~124		$	$(33	~~199,952~~)		$	~~205,130~~186		$	~~185,706~~		$	~~570,072~~
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	~~137~~177			9	~~122~~			~~277~~152			~~152~~			~~421~~
Trunkline	~~169~~180			12	~~172~~			~~354~~177			~~177~~			~~549~~
Sea Robin	2440			2	24			4720			20			92

(1) Reservation revenues comprised ~~88% and~~ 89% of total operating revenues infor the ~~2012~~three ~~and~~months ~~2011~~ended ~~three~~March ~~month periods~~31, ~~respectively~~2013. Reservation revenues comprised 88% of total operating revenues in both the successor ~~period from March 26, 2012 to September 30, 2012,~~ and ~~88%~~predecessor ~~and~~periods ~~89% of total operating revenues~~ in ~~the~~ 2012 ~~and 2011 predecessor periods, respectively~~.


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

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

• ~~Unconsolidated~~Operating ~~Investments~~Revenues. ~~The~~Operating ~~primary~~revenues ~~driver~~ for the ~~reduction~~three inmonths ~~Segment~~ended ~~Adjusted~~March ~~EBITDA~~31, ~~for~~2013 ~~the~~decreased ~~Company's~~slightly ~~Transportation~~compared ~~and Storage segment was the contribution of Citrus~~ to ~~ETP. Citrus was reflected in Adjusted EBITDA attributable to unconsolidated investments for all of~~ the predecessor ~~periods~~and ~~shown above but was not reflected in the~~ successor periods. ~~The~~in ~~predecessor~~2012 ~~periods~~primarily ~~reflected~~due ~~Adjusted EBITDA attributable~~ to ~~Citrus~~lower ofcapacity ~~$79.3~~sold ~~million~~at ~~and~~lower ~~$193.3~~rates ~~million for the three~~ and ~~nine~~lower ~~months~~parking ~~ended September 30~~revenues, ~~2011,~~the ~~respectively,~~impacts ~~and~~of ~~$60.9~~which ~~million~~were ~~for~~partially ~~the~~offset ~~period~~by ~~from~~higher ~~January~~usage 1,revenues ~~2012~~as toa ~~March~~result ~~25,~~of ~~2012~~higher volumes.

• Operating ~~Revenues. On a daily average basis~~, ~~operating~~Maintenance ~~revenues~~and ~~were~~General ~~slightly~~Expenses. ~~lower~~The inperiod ~~the~~from ~~successor~~March ~~periods~~26, ~~primarily~~2012 ~~due~~ to ~~the~~March ~~impact~~31, in2012 ~~the~~included ~~successor~~$41 ~~periods~~million ~~from~~of ~~lower~~merger-related ~~summer~~employee ~~capacity~~severance ~~being sold~~expenses.

• ~~Operating,~~Unconsolidated ~~Maintenance~~Investments. ~~and~~The ~~General~~primary ~~Expenses.~~driver ~~The~~for ~~period~~the ~~from~~reduction ~~March~~in ~~26,~~Segment ~~2012~~Adjusted toEBITDA ~~September~~for ~~30,~~the ~~2012~~Company’s ~~included~~Transportation ~~$43.8~~and ~~million~~Storage ofsegment ~~merger-related~~was ~~employee~~the ~~severance~~contribution ~~expenses.~~of ~~The~~Citrus ~~nine~~to ~~months~~ETP ~~ended~~on ~~September~~March 3026, ~~2011~~2012. Citrus was reflected ~~legal~~in ~~expenses~~Adjusted ~~that~~EBITDA ~~were~~attributable ~~lower~~to onunconsolidated ainvestments ~~daily~~for ~~average~~the ~~basis~~predecessor ~~than~~period ~~the~~shown ~~legal~~above ~~expenses~~but ~~recorded~~was ~~during~~not ~~the~~reflected ~~predecessor~~in ~~and~~the successor periods. inThe ~~2012;~~period ~~this~~from ~~was~~January ~~due~~1, 2012 to ~~settlement~~March in25, ~~2011~~2012 ofreflected ~~certain~~Adjusted ~~litigation~~EBITDA ~~with~~attributable ~~several contractors related~~ to ~~the~~Citrus ~~Company's~~of ~~East~~$61 ~~End projects~~million.

Gathering and Processing Segment

The Gathering and Processing segment is primarily engaged in connecting producing wells of exploration and production ~~(E&P)~~ companies to its gathering system, providing compression and gathering services, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGL, and redelivering natural gas and NGL to a variety of markets. Its operations are conducted through SUGS, which was contributed to Regency on April 30, 2013. SUGS’ natural gas supply contracts primarily include fee-based, percent-of-proceeds and margin sharing (conditioning fee and wellhead) purchase contracts. These natural gas supply contracts vary in length from month-to-month to a number of years, with many of the contracts having a term of three to five years. SUGS’ primary sales customers include ~~E&P~~exploration and production companies, power generating companies, electric and gas utilities, energy marketers, industrial end-users located primarily in the Gulf Coast and southwestern United States, and petrochemical companies. With respect to customer demand for the products and services it ~~provides, SUGS’ business is not generally seasonal in nature; however, SUGS’ operations and the operations of its natural gas producers can be adversely impacted by severe weather.~~

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services. The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control. The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments. For additional information related to the Company’s commodity price risk management, see Note 9.25

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~~The~~provides, ~~following~~SUGS’ ~~table~~business ~~presents~~is ~~the~~not ~~results~~generally ofseasonal ~~operations~~in ~~applicable~~nature; tohowever, ~~the Company~~SUGS’s ~~Gathering~~operations and ~~Processing~~the ~~segment~~operations ~~for~~of ~~the~~its ~~period~~natural ~~presented~~gas producers can be adversely impacted by severe weather.

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

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



	Successor						Predecessor
	Three Months Ended March 31, 2013			Period from Acquisition (March 26, 2012) to March 31, 2012			Period from January 1, 2012 to March 25, 2012
Operating revenues	$	190		$	20		$	246
Cost of natural gas and other energy ⁽¹⁾	(157		)	(14		)	(196		)
Gross margin ⁽²⁾	33			6			50
Operating, maintenance and general, excluding non-cash compensation expense and accretion	(37		)	(17		)	(23		)
Taxes other than on income and revenues	(2		)	—			(2		)
Segment Adjusted EBITDA	$	(6	)	$	(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 ~~variance~~variances impacting Segment Adjusted EBITDA for the Company'’s Gathering and Processing segment.

• Gross Margin. ~~For~~Gross margin for the three months ended ~~September~~March 3031, ~~2012~~2013 decreased compared to the predecessor and successor periods in 2012 due to decreases in natural gas and NGL sales volumes and a decrease in market-driven 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 ~~September~~March 3031, ~~2011~~2013, ~~the~~compared ~~decrease~~to in$2.44 ~~Gathering~~per MMBtu and ~~Processing~~$1.17 ~~Segment~~per ~~Adjusted~~gallon ~~EBITDA~~for ~~was~~the ~~primarily~~period ~~due~~from March 26, 2012 to ~~lower~~March ~~gross~~31, ~~margin~~2012 ofand $122.644 per MMBtu and $1.17 per gallon for the period from January 1, 2012 to March 25, 2012.

3726

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

• Operating, Maintenance and General Expenses. ~~The~~Operating, ~~period~~maintenance ~~from~~and general expenses increased during the three months ended March 2631, ~~2012~~2013 due to ~~September~~expansion ~~30,~~of ~~2012~~the ~~included~~SUGS ~~$16~~system.2 ~~million~~This ofchange ~~merger-related~~was ~~employee~~offset ~~severance~~by ~~expenses.~~the Onabsence aof ~~daily~~$15 ~~basis,~~million ~~operating,~~in ~~maintenance~~merger-related ~~and~~employee ~~general~~severance expenses ~~have~~that ~~also~~were ~~increased~~incurred ~~between~~during the ~~end~~period offrom ~~the~~March ~~periods~~26, ~~presented~~2012 ~~due~~ to ~~expansion~~March of31, ~~plant facilities~~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 31, 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 13 to our consolidated financial statements.

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

	Successor				~~Predecessor~~			~~Successor~~Predecessor			~~Predecessor~~
	Three months ended September 30, 2012				Three months ended September 30, 2011			Period from Acquisition (March 26, 2012) to September 30, 2012			Period from January 1, 2012 to March 25, 2012			Nine months ended September 30, 2011
	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 operating revenues (1)	$	52,694			$	49,993		$	114,442		$	65,675		$	173,465
Amounts reported within discontinued operations:
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(26,779		)		(32,395		)	(70,981		)	(29,265		)	(105,637		)
Net operating revenues (1)	$	73		$	5			$	66
Taxes other than on income and revenues	(3,454		)		(3,229		)	(7,554		)	(2,856		)	(9,155		)
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(30		)	(14		)		(29		)
Segment Adjusted EBITDA	$	22,461			$	14,369		$	35,907		$	33,554		$	58,673
Taxes other than on income and revenues	(4		)	(1		)		(3		)
Operating Information:
Segment Adjusted EBITDA	$	39		$	(10	)		$	34
Natural gas sales volumes (MMcf)	3,047				3,182			10,300			19,957			43,002
Operating Information:
Natural gas transported volumes (MMcf)	5,068				3,806			10,902			7,379			18,583
Natural gas sales volumes (MMcf)	27,629			2,177				19,957
Weather – Degree Days: (2)
Natural gas transported volumes (MMcf)	8,657			629				7,379
Missouri Gas Energy service territories	50				94			293			1,898			3,495
Weather – Degree Days: (2)
New England Gas Company service territories	68				49			806			2,170			3,634
Missouri Gas Energy service territories	2,676			1				1,898
New England Gas Company service territories	2,309			139				2,170

38(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.

(12) “Degree ~~Operating~~days” ~~revenues~~are ~~for~~a measure of the ~~Distribution~~coldness ~~segment~~of ~~are~~the ~~reported~~weather ~~net~~experienced. A ofdegree ~~cost~~day ofis ~~natural~~equivalent ~~gas~~to ~~and~~each ~~other~~degree ~~energy~~that ~~and~~the ~~revenue-related~~mean ~~taxes,~~temperature ~~which~~for ~~are~~a ~~pass-through~~day ~~costs~~falls below 65 degrees Fahrenheit.

~~(2)~~Following ~~"Degree~~is ~~days" are~~ a ~~measure~~discussion of the ~~coldness~~significant ofitems ~~the~~and ~~weather~~variances ~~experienced.~~impacting ASegment ~~degree~~Adjusted ~~day~~EBITDA isfor ~~equivalent to each degree that~~ the ~~daily~~Company’s ~~mean~~Distribution ~~temperature for a day falls below 65 degrees Fahrenheit~~segment.

~~Following~~• isNet aOperating ~~discussion~~Revenues. ofThe ~~the~~three ~~significant~~months ~~items~~ended ~~and~~March ~~variance~~31, ~~impacting~~2013 ~~Segment~~were ~~Adjusted~~higher ~~EBITDA~~compared ~~for~~to the ~~Company's~~predecessor ~~Distribution~~and ~~segment~~successor periods in 2012 primarily due to colder-than-normal temperatures and a longer heating season.

• ~~Net~~ Operating ~~Revenues. For the three months ended September 30~~, ~~2012~~Maintenance ~~compared~~and toGeneral ~~the~~Expenses. ~~three~~This ~~months~~decrease ~~ended~~was ~~September 30, 2011, net operating revenues increased $2.7 million~~ primarily due to a $~~9.8~~12 million ~~decrease~~ in ~~gas~~merger-related ~~cost~~expenses ~~offset~~incurred byduring athe ~~$7.5~~period ~~million~~from ~~decrease~~March ~~in operating revenues. With respect to year-to-date results~~26, ~~the predecessor and successor periods in~~ 2012 ~~also were higher (on a daily basis) compared~~ to ~~the~~March ~~year-to-date period in 2011 due to new customer rates at New England Gas Company effective April 1~~31, ~~2011~~2012.

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

Corporate and Other Activities

The period from January 1, 2012 to March 25, 2012 included $~~18.7~~19 million ofin merger-related expenses.

~~See Note 3 for additional information related to the Company's merger with ETE.~~ 27

Table of Contents

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of the Company has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the ETE Merger for the ~~nine~~three months ended ~~September~~March 3031, 2012 ~~and 2011~~, giving effect to the ETE Merger as if it had occurred on January 1, ~~2011~~2012. This unaudited pro forma financial information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if ~~the~~these ~~ETE~~transactions ~~Merger~~ had been consummated on January 1, ~~2011~~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
OPERATING REVENUES	$	31		$	443		$	—			$	474
OPERATING EXPENSES:
Cost of natural gas and other energy	14			197							211
Operating, maintenance and general	61			116			(72		)	(a)	105
Depreciation and amortization	4			49			6			(b)	59
Total operating expenses	79			362			(66		)		375
OPERATING INCOME	(48		)	81			66				99
OTHER INCOME (EXPENSE):
Interest expense	(4		)	(50		)	9			(c)	(45		)
Earnings from unconsolidated investments	—			16			(9		)	(d)	7
Other, net	—			(2		)	—				(2		)
Total other expenses, net	(4		)	(36		)	—				(40		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	(52		)	45			66				59
Income tax expense (benefit)	(12		)	12			23			(e)	23
INCOME (LOSS) FROM CONTINUING OPERATIONS	(40		)	33			43				36
Income from discontinued operations	1			17			—				18
NET INCOME (LOSS)	$	(39	)	$	50		$	43			$	54

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


(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.

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

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


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

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

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

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

~~Analysis of Supplemental Pro Forma Financial Information~~28

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

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Company’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. The Company performed an evaluation under the supervision and with the participation of management, including its principal executive officer and principal financial officer, and with the participation of personnel from its Legal, Internal Audit, Risk Management and Financial Reporting Departments, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this report. Based on that evaluation, Southern Union’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2012~~2013.

41Changes In Internal Control Over Financial Reporting

~~Changes~~Subsequent to the merger with ETE in ~~Internal~~March ~~Control~~2012, the Company's internal controls over ~~Financial~~financial ~~Reporting~~reporting, including certain disclosure controls and corporate governance procedures, have been impacted by changes made to conform to the existing controls of ETP and ETE. During the three months ended March 31, 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 of these changes are in response to any identified deficiency or weakness in the Company's internal control over financial reporting.

~~Subsequent~~There towere ~~the~~no ~~merger~~other ~~with~~changes ~~ETE~~ in ~~March 2012,~~ the Company’'s internal controls over financial reporting, ~~including~~that ~~certain~~have ~~disclosure~~materially ~~controls and corporate governance procedures~~affected, ~~have~~or ~~been impacted by changes made to conform to the existing controls of ETE. Additional changes~~ are ~~expected~~reasonably tolikely ~~occur in future periods. None of these changes are in response~~ to ~~any~~affect, ~~identified~~its ~~deficiency 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.~~LEGAL PROCEEDINGS

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Note 11 ~~– Commitments and Contingencies,~~ in this Quarterly Report on Form 10-Q and in ~~the~~ Note 14 ~~– Commitments and Contingencies, information~~ included in the Company’s Form 10-K for the year ended December 31, ~~2011~~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 11 ~~– Commitments and Contingencies,~~ in this Quarterly Report on Form 10-Q and ~~in the~~ Note 14 ~~– Commitments and Contingencies, information~~ included in the Company’s Form 10-K for the year ended December 31, ~~2011~~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 ~~February~~March 241, ~~2012~~2013.

~~ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.~~29

~~None.~~Table of Contents

ITEM 36. ~~Defaults~~ ~~Upon~~EXHIBITS ~~Senior Securities.~~

~~Item~~The 3,following ~~Defaults~~exhibits ~~Upon~~are ~~Senior~~filed ~~Securities,~~as ~~has~~part ~~been~~of ~~omitted from~~ this Quarterly report ~~pursuant~~on ~~to the reduced disclosure format permitted by General Instruction H to~~ Form 10-Q.:

ITEM 4. Mine Safety Disclosures.



Exhibit No.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.
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

~~N/A~~30

~~ITEM~~Table ~~5. Other~~of ~~Information.~~Contents

None.

ITEM 6. Exhibits.

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

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

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

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the ~~Registrant~~registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		SOUTHERN UNION COMPANY
		(Registrant)
Date:	~~November~~May 89, ~~2012~~2013	By:	/s/ ~~MARTIN~~Martin ~~SALINAS~~Salinas, JRJr.
			Martin Salinas, Jr.
			Chief Financial Officer (duly authorized to sign on behalf of the registrant)

4431

Predecessor

Three Months Ended
March 31, 2013

Period from Acquisition (March 26, 2012) to March 31, 2012

Period from January 1, 2012 to March 25, 2012

Revenue from discontinued operations

Net income of discontinued operations, excluding effect of taxes and overhead allocations