UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2012

or

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

Commission File No. 1-6407

____________________________

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

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

(713) 989-2000

(Registrant’s telephone number, including area code)

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

Yes xNo ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes xNo ¨

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

Large accelerated filer x    Accelerated filer ¨    Non-accelerated filer ¨    Smaller reporting company ¨

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

Yes ¨    No x

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

June 30, 2012

Table of Contents

	Page
PART I.  FINANCIAL INFORMATION	1
Glossary	1
ITEM 1.  Financial Statements (Unaudited)	3
Condensed Consolidated Balance Sheet	4
Condensed Consolidated Statement of Operations	6
Condensed Consolidated Statements of Comprehensive Income (Loss)	7
Condensed Consolidated Statements of Cash Flows	8
Condensed Consolidated Statement of Stockholders' Equity	9
Notes to Consolidated Financial Statements	10
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk	42
ITEM 4. Controls and Procedures	42
PART II. OTHER INFORMATION	43
ITEM 1. Legal Proceedings	43
ITEM 1A. Risk Factors	43
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
ITEM 3. Defaults Upon Senior Securities	43
ITEM 4. Mine Safety Disclosures	43
ITEM 5. Other Information	43
ITEM 6. Exhibits	44
SIGNATURE	45

PART I — FINANCIAL INFORMATION

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Southern Union Company and its subsidiaries (“Southern Union” or the “Company”) in periodic press releases and some oral statements of Southern Union officials during presentations about the Company, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Company believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Company’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see "Part I - Item 1A. Risk Factors” in the Company's Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 24, 2012.

GLOSSARY

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

AFUDC    Allowance for funds used during construction

Btu    British thermal units

CEO    Chief Executive Officer

CFO    Chief Financial Officer

Citrus    Citrus Corp.

Company    Southern Union and its subsidiaries

EITR    Effective income tax rate

EPA    United States Environmental Protection Agency

ETE    Energy Transfer Equity, L.P.

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

Exchange Act    Securities Exchange Act of 1934

FERC    Federal Energy Regulatory Commission    

Florida Gas    Florida Gas Transmission Company, LLC

GAAP    Accounting principles generally accepted in the United States of America

Gallons/d    Gallons per day

Holdco    ETP Holdco Corporation

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

PRPs    Potentially responsible parties

RCRA    Resource Conservation and Recovery Act

SARs    Stock appreciation rights

1

Sea Robin    Sea Robin Pipeline Company, LLC

SEC    United States Securities and Exchange Commission

Sigma    Sigma Acquisition Corporation

Southern Union    Southern Union Company    

SUGS    Southern Union Gas Services

Sunoco    Sunoco, Inc.

TBtu    Trillion British thermal units

TCEQ    Texas Commission on Environmental Quality

Trunkline    Trunkline Gas Company, LLC

Trunkline LNG    Trunkline LNG Company, LLC

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

2

ITEM 1. FINANCIAL STATEMENTS

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(In thousands)

ASSETS
	Successor			Predecessor
	June 30, 2012			December 31, 2011
Current assets:
Cash and cash equivalents	$	11,497		$	23,640
Accounts receivable net of allowances of $1,304 and $2,325 respectively	161,788			270,741
Accounts receivable — affiliates	10,427			10,467
Inventories	190,694			204,235
Deferred natural gas purchases	42,334			50,716
Natural gas imbalances — receivable	40,886			54,549
Prepayments and other assets	45,390			42,675
Total current assets	503,016			657,023
Property, plant and equipment:
Plant in service	6,850,887			7,195,747
Construction work in progress	180,841			103,862
	7,031,728			7,299,609
Less: Accumulated depreciation and amortization	(68,093		)	(1,573,273		)
Net property, plant and equipment	6,963,635			5,726,336
Deferred charges:
Regulatory assets	132,678			57,447
Other deferred charges	74,344			60,407
Total deferred charges	207,022			117,854
Unconsolidated investments	126,300			1,633,289
Goodwill	2,030,273			89,227
Other	67,202			47,130
Total assets	$	9,897,448		$	8,270,859

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(Dollars in thousands, except par value)

LIABILITIES AND STOCKHOLDERS' EQUITY
	Successor			Predecessor
	June 30, 2012			December 31, 2011
Current liabilities:
Current portion of long–term debt	$	853		$	343,254
Notes payable	235,000			200,000
Notes payable — related party	166,217			—
Accounts payable and accrued liabilities	108,368			193,949
Accounts payable and accrued liabilities — related parties	8,548			178
Federal, state and local taxes payable	38,958			37,127
Accrued interest	32,596			33,837
Natural gas imbalances — payable	121,111			145,212
Derivative instruments	34,195			58,598
Other	96,178			112,135
Total current liabilities	842,024			1,124,290
Long–term debt obligations	3,111,683			3,160,372
Deferred credits	358,358			301,709
Accumulated deferred income taxes	1,695,231			1,044,877
Commitments and contingencies (Note 11)
Stockholders’ 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	3,913,000			1,934,102
Less: Treasury stock, nil and 1,298 shares, respectively, at cost	—			(33,228		)
Less: Common stock held in trust, nil and 581 shares, respectively	—			(10,888		)
Deferred compensation plans	—			10,888
Accumulated other comprehensive income (loss)	3,934			(119,192		)
Retained earnings (accumulated losses)	(26,782		)	731,787
Total stockholders' equity	3,890,152			2,639,611
Total liabilities and stockholders' equity	$	9,897,448		$	8,270,859

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands)

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Operating revenues	$	472,470		$	631,607
Operating expenses:
Cost of natural gas and other energy	175,961			315,575
Operating, maintenance and general	124,248			123,858
Depreciation and amortization	74,476			59,295
Revenue–related taxes	4,142			5,200
Taxes, other than on income and revenues	14,604			12,657
Total operating expenses	393,431			516,585
Operating income	79,039			115,022
Other income (expenses):
Interest expense	(57,303		)	(54,933		)
Earnings from unconsolidated investments	672			25,048
Other, net	175			224
Total other expenses, net	(56,456		)	(29,661		)
Earnings before income taxes	22,583			85,361
Income tax expense	10,858			25,588
Net earnings	$	11,725		$	59,773

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Operating revenues	$	512,182		$	633,649		$	1,378,429
Operating expenses:
Cost of natural gas and other energy	193,487			311,270			741,207
Operating, maintenance and general	185,281			134,921			244,852
Depreciation and amortization	79,199			56,544			118,622
Revenue–related taxes	4,535			9,867			22,567
Taxes, other than on income and revenues	16,729			14,296			28,127
Total operating expenses	479,231			526,898			1,155,375
Operating income	32,951			106,751			223,054
Other income (expenses):
Interest expense	(61,684		)	(50,407		)	(110,504		)
Earnings from unconsolidated investments	684			16,160			51,749
Other, net	191			284			366
Total other expenses, net	(60,809		)	(33,963		)	(58,389		)
Earnings (loss) before income taxes	(27,858		)	72,788			164,665
Income tax expense (benefit)	(1,076		)	22,871			44,230
Net earnings (loss)	$	(26,782	)	$	49,917		$	120,435

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

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(In thousands)

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Net earnings	$	11,725		$	59,773
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	—			(11,587		)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,362
Change in fair value of commodity hedges	6,134			344
Reclassification of unrealized gain on commodity hedges into earnings	(3,541		)	(2,977		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			706
Change in other comprehensive income from equity investments	198			37
	2,791			(10,115		)
Comprehensive income	$	14,516		$	49,658

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Net earnings (loss)	$	(26,782	)	$	49,917		$	120,435
Other comprehensive income (loss), net of tax:
Change in fair value of interest rate hedges	—			3,878			(12,991		)
Reclassification of unrealized loss on interest rate hedges into earnings	—			4,946			6,685
Change in fair value of commodity hedges	7,277			2,954			(649		)
Reclassification of unrealized gain on commodity hedges into earnings	(3,541		)	(1,307		)	(5,874		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			1,815			1,407
Change in other comprehensive income from equity investments	198			29			72
	3,934			12,315			(11,350		)
Comprehensive income (loss)	$	(22,848	)	$	62,232		$	109,085

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

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Cash flows from operating activities:
Net earnings (loss)	$	(26,782	)	$	49,917		$	120,435
Adjustments to reconcile net earnings to net cash flows provided by operating activities:
Depreciation and amortization	79,199			56,544			118,622
Deferred income taxes	(1,558		)	22,866			51,543
Provision for bad debts	3,904			1,013			9,864
Amortization of costs charged to interest	(8,544		)	1,165			2,654
Net gain on curtailment of OPEB plans	(15,332		)	—			—
Unrealized loss on derivatives	19,709			—			14,413
Share–based compensation expense	133			1,654			4,899
Earnings from unconsolidated investments, adjusted for cash distributions	1,673			(16,160		)	(50,249		)
Changes in operating assets and liabilities, net of Merger impact	(181,173		)	79,919			78,730
Net cash flows provided by (used in) operating activities	(128,771		)	196,918			350,911
Cash flows from investing activities:
Additions to property, plant and equipment	(81,512		)	(60,062		)	(143,902		)
Loan to unconsolidated investments	—			—			(72,000		)
Loan repayment from unconsolidated investments	—			37,000			—
Proceeds from Citrus Merger	—			1,895,000			—
Plant retirements and other	(1,997		)	(2,252		)	(488		)
Net cash flows provided by (used in) investing activities	(83,509		)	1,869,686			(216,390		)
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		)	(2,138		)
Dividends paid on common stock	—			(18,726		)	(37,390		)
Note payable — related party	221,217			—			—
Repayment of note payable-related party	(55,000		)	—			—
Repayment of long-term debt obligation	(138		)	(1,047,529		)	(278		)
Net change in revolving credit facilities	22,614			12,386			(101,572		)
Purchase of treasury stock	—			(1,450,000		)	—
Other	—			(2,780		)	6,571
Net cash flows provided by (used in) financing activities	186,985			(2,053,452		)	(134,807		)
Change in cash and cash equivalents	(25,295		)	13,152			(286		)
Cash and cash equivalents at beginning of period	36,792			23,640			3,299
Cash and cash equivalents at end of period	$	11,497		$	36,792		$	3,013

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

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

	Common Stock		Premium on Capital Stock			Treasury Stock, at cost			Common Stock Held In Trust			Deferred Compen- sation Plans			Accumulated Other Comprehensive Income (Loss)			Retained Earnings (Accumu-lated Losses)			Total Stock- holders' Equity
Predecessor
Balance December 31, 2011	$	126,142	$	1,934,102		$	(33,228	)	$	(10,888	)	$	10,888		$	(119,192	)	$	731,787		$	2,639,611
Other comprehensive income, net of tax	—		—			—			—			—			12,315			—			12,315
Share–based compensation	—		1,654			—			—			—			—			—			1,654
Restricted stock issuances	186		(186		)	(2,864		)	—			—			—			—			(2,864		)
Exercise of stock options	5		79			—			—			—			—			—			84
Contributions to Trust	—		—			—			(399		)	399			—			—			—
Disbursements from Trust	—		—			—			650			(650		)	—			—			—
Purchase of treasury stock	—		—			(1,450,000		)	—			—			—			—			(1,450,000		)
Net earnings	—		—			—			—			—			—			49,917			49,917
Balance March 25, 2012	$	126,333	$	1,935,649		$	(1,486,092	)	$	(10,637	)	$	10,637		$	(106,877	)	$	781,704		$	1,250,717
Successor
Balance March 26, 2012	$	—	$	3,912,867		$	—		$	—		$	—		$	—		$	—		$	3,912,867
Other comprehensive income, net of tax	—		—			—			—			—			3,934			—			3,934
Non-cash compensation expense	—		133			—			—			—			—			—			133
Net earnings	—		—			—			—			—			—			(26,782		)	(26,782		)
Balance June 30, 2012	$	—	$	3,913,000		$	—		$	—		$	—		$	3,934		$	(26,782	)	$	3,890,152

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

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

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(Tabular dollar amounts are in thousands)

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

1. DESCRIPTION OF BUSINESS:

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

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

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

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

See Note 3 – ETE Merger for information related to the Company’s merger with ETE on March 26, 2012.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

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

Business Combination Accounting

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

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

10

3. ETE MERGER AND PENDING HOLDCO TRANSACTION:

Description of Merger

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

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

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

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

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

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

In connection with the consummation of the 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).

11

Restrictions on each awards of cash restricted stock units (RSU) outstanding immediately prior to the Effective Time expired and each RSU 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 RSU, less (ii) any applicable deductions and withholdings required by law.

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 $1.895 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 $70.6 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.  

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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 June 30, 2012 have been changed from amounts reflected as of March 31, 2012 based on management's review of valuation. Management is continuing to review the valuation and expects to be substantially complete with the purchase price allocation in the third quarter of 2012.

Cash and cash equivalents	$	36,792
Other current assets	524,246
Property and equipment	6,958,768
Goodwill	2,030,273
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	$	3,912,868

⁽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.

Pending Holdco Transaction

On June 15, 2012, ETE and ETP entered into a transaction agreement pursuant to which, immediately following the closing of ETP's acquisition of Sunoco, (i) ETE will contribute its interest in Southern Union into an ETP-controlled entity in exchange for a 60% equity interest in the new entity ("Holdco") and (ii) ETP will contribute its interest in Sunoco to Holdco and will retain a 40% equity interest in Holdco. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. Consequently, ETP expects to consolidate Holdco (including Sunoco and Southern Union) in its consolidated financial statements subsequent to consummation of the Holdco Transaction.

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4. RELATED PARTY TRANSACTIONS:

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

	Successor		Predecessor
	June 30, 2012		December 31, 2011
Investment in ETP	$	103,681	$	—
Accounts receivable — affiliates (1)	$	10,427	$	10,467
Note payable — ETE (2)	$	166,217	$	—
Accounts payable — affiliates (3)	$	8,548	$	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 statement of operations. Prior period amounts were not included as they were immaterial.

	Successor
	Three months ended June 30, 2012
Operating revenue — ETE	$	6,794
Cost of natural gas and other energy	5,614
Operating, maintenance and general	4,138
Interest expense	1,780
Equity in Earnings	673

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5. COMPREHENSIVE INCOME (LOSS):

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

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	(6,891	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			2,253
Change in fair value of commodity hedges	3,457			194
Reclassification of unrealized gain on commodity hedges into earnings	(1,995		)	(1,678		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			568
Change in other comprehensive income from equity investments	—			21
	$	1,462		$	(5,533	)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Income taxes included in other comprehensive income (loss):
Change in fair value of interest rate hedges	$	—		$	2,296		$	(7,757	)
Reclassification of unrealized loss on interest rate hedges into earnings	—			3,139			4,481
Change in fair value of commodity hedges	4,100			1,665			(365		)
Reclassification of unrealized gain on commodity hedges into earnings	(1,995		)	(736		)	(3,310		)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings	—			902			1,142
Change in other comprehensive income from equity investments	—			18			43
	$	2,105		$	7,284		$	(5,766	)

The table below presents the components in Accumulated other comprehensive income (loss) as of the dates indicated:

	Successor		Predecessor
	June 30, 2012		December 31, 2011
Interest rate hedges, net	$	—	$	(50,259	)
Commodity hedges, net	3,736		(11		)
Benefit plans:
Net actuarial loss and prior service costs, net — pensions	—		(51,845		)
Net actuarial gain and prior service credit, net — OPEB	—		(14,542		)
Equity investments, net	198		(2,535		)
Total accumulated other comprehensive income (loss), net of tax	$	3,934	$	(119,192	)

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6. DEBT OBLIGATIONS:

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

	Successor		Predecessor
	June 30, 2012		December 31, 2011
Long-Term Debt Obligations:
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	7,465		7,746
Unamortized fair value adjustments	53,813		—
	1,340,543		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	150,688		—
	1,771,993		1,966,615
Total Long-Term Debt Obligations	3,112,536		3,503,626
Credit Facilities	235,000		200,000
Note Payable — ETE	166,217		—
Total consolidated debt obligations	3,513,753		3,703,626
Less: Current portion of long term debt	853		343,254
Less: Short-term debt	401,217		200,000
Total long-term debt	$	3,111,683	$	3,160,372
Total fair value of consolidated debt obligations	$	3,542,118	$	3,964,549

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

The fair value of the Company’s term loans and credit facilities as of June 30, 2012 and December 31, 2011 were determined using the market approach, which utilized Level 2 inputs consisting of reported recent loan transactions for parties of similar credit quality and remaining life, as there is no active secondary market for loans of these types and sizes.

The fair value of the Company’s other long-term debt as of June 30, 2012 and December 31, 2011 was also determined using the market approach, which utilized observable market data to corroborate the estimated credit spreads and prices for the Company’s non-bank long-term debt securities in the secondary market.  Those valuations were based in part upon the reported trades of the Company’s non-bank long-term debt securities where available and the actual trades of debt securities of similar credit quality and remaining life where no secondary market trades were reported for the Company’s non-bank long-term debt securities. 

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Interest Rate Swaps.  The Company has 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 – Derivative Instruments and Hedging Activities – Interest Rate Contracts – Interest Rate Swaps for more information regarding these swap agreements.

Credit Facilities.  In March 2012, the Company entered into the Eighth Amended and Restated Revolving Credit Agreement with certain banks in the amount of $700 million (2012 Revolver).  The 2012 Revolver is an amendment, restatement and refinancing of the Company’s $550 million Seventh Amended and Restated Revolving Credit Agreement.  The 2012 Revolver is scheduled to mature on May 20, 2016.  The Company entered into the 2012 Revolver in order to (i) obtain consent to the transactions contemplated by the Merger Agreement, the Citrus Merger Agreement and the Support Agreement; (ii) to increase the amount of the facility from $550 million to $700 million; and (iii) to modify certain covenants.  Borrowings under the 2012 Revolver are available for the Company’s working capital, other general corporate purposes and letter of credit requirements.  The interest rate and commitment fee under the 2012 Revolver are calculated using a pricing grid, which is based upon the credit rating for the Company’s senior unsecured notes.  The annualized interest rate and commitment fee rate bases for the 2012 Revolver at 2012 were LIBOR plus 162.5 basis points and 25 basis points, respectively.

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 drawdowns from its 2012 Revolver.

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 RSUs; 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.

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7. BENEFITS:

Components of Net Periodic Benefit Cost

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

	Pension Benefits						Other Postretirement Benefits
	Successor			Predecessor			Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011			Three months ended June 30, 2012			Three months ended June 30, 2011
Net Periodic Benefit Cost:
Service cost	$	2,083		$	935		$	206		$	881
Interest cost	(1,651		)	2,525			611			1,446
Expected return on plan assets	(756		)	(2,647		)	(1,623		)	(1,450		)
Prior service cost (credit) amortization	—			147			—			(453		)
Actuarial loss (gain) amortization	172			1,984			—			(403		)
	(152		)	2,944			(806		)	21
Regulatory adjustment (2)	493			191			666			666
Net periodic benefit cost	$	341		$	3,135		$	(140	)	$	687

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011			Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Net Periodic Benefit Cost:
Service cost	$	2,177		$	998		$	1,870		$	223		$	881		$	1,761
Interest cost	(1,462		)	2,095			5,050			662			1,254			2,892
Expected return on plan assets	(1,005		)	(2,461		)	(5,293		)	(1,758		)	(1,367		)	(2,899		)
Prior service cost (credit) amortization	—			133			294			—			(409		)	(906		)
Actuarial loss (gain) amortization	172			2,308			3,967			—			273			(806		)
Curtailment recognition (1)	—			—			—			(15,332		)	—			—
	(118		)	3,073			5,888			(16,205		)	632			42
Regulatory adjustment (2)	497			253			383			675			657			1,332
Net periodic benefit cost	$	379		$	3,326		$	6,271		$	(15,530	)	$	1,289		$	1,374

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

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

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8. TAXES ON INCOME:

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

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Current:
Federal	$	—		$	136
State	482			716
	482			852
Deferred:
Federal	9,007			24,419
State	1,369			317
	10,376			24,736
Total federal and state income tax expense	$	10,858		$	25,588
Effective tax rate	48		%	30		%

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Current:
Federal	$	—		$	—		$	173
State	482			5			(7,486		)
	482			5			(7,313		)
Deferred:
Federal	(1,814		)	19,861			48,604
State	256			3,005			2,939
	(1,558		)	22,866			51,543
Total federal and state income tax expense (benefit)	$	(1,076	)	$	22,871		$	44,230
Effective tax rate	4		%	31		%	27		%

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 to the Company 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 and NGL processing spread swaps are the principal derivative instruments used by the Company to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time.  The Company recognizes all derivative instruments as assets or liabilities at fair value in the unaudited interim Condensed Consolidated Balance Sheet.

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Interest Rate Contracts

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

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

The Company also had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million to hedge the LNG Holdings $455 million term loan, which was refinanced in February 2012.  These interest rate swaps were accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive income and reclassified 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 June 30, 2012, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods were associated with interest payments on outstanding long-term debt.  During the predecessor periods, these treasury rate locks were accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive income and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

Commodity Contracts – Gathering and Processing Segment

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

Natural Gas Price Swaps.  As of June 30, 2012, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 5,520,000 MMBtu for the remainder of 2012 and 10,037,500 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 June 30, 2012, approximately $8.0 million of net after-tax losses in Accumulated other comprehensive income related to these natural gas price swaps are expected to be recognized in Operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Price Swaps.  As of June 30, 2012, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 32,898,096 gallons (2,760,000 MMBtu equivalent basis) for the remainder of 2012.  These NGL price swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive income and reclassified into Operating revenues in the same periods during which the forecasted NGL sales impact earnings.  As of June 30, 2012, approximately $9.1 million of net after-tax gains in Accumulated other comprehensive income related to these NGL price swaps are expected to be recognized in Operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

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.

20

Natural Gas Price Swaps.  As of June 30, 2012, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 7,290,000 MMBtu, 10,770,000 MMBtu and 1,690,000 MMBtu for the remainder of 2012, 2013 and 2014, respectively.  These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s asset and liability derivative instruments and their location reported in the unaudited interim Condensed Consolidated Balance Sheet at the dates indicated:

	Fair Value (1)
	Asset Derivatives				Liability Derivatives
	Successor		Predecessor		Successor		Predecessor
Balance Sheet Location	June 30, 2012		December 31, 2011		June 30, 2012		December 31, 2011
Cash Flow Hedges:
Interest rate contracts
Derivative instruments — liabilities	$	—	$	—	$	—	$	19,936
Deferred credits	—		—		—		59,789
Commodity contracts — Gathering and Processing:
Natural gas price swaps
Prepayments and other assets	3,571		6,124		—		—
Accounts payable — related parties	—		—		2,365		—
Deferred credits	—		—		2,145		—
NGL price swaps
Prepayments and other assets	11,319		—		—		1,996
Derivative instruments — liabilities	—		—		—		4,144
	$	14,890	$	6,124	$	4,510	$	85,865
Economic Hedges:
Interest rate contracts
Derivative instruments — liabilities	$	—	$	—	$	16,432	$	—
Deferred credits	—		—		68,314		—
Commodity contracts — Gathering and Processing:
Other derivative instruments
Derivative instruments — liabilities	—		—		—		50
Commodity contracts — Distribution:
Natural gas price swaps
Derivative instruments — liabilities	—		—		17,763		34,468
Deferred credits	—		3		291		5,643
	$	—	$	3	$	102,800	$	40,161
Total	$	14,890	$	6,127	$	107,310	$	126,026

⁽¹⁾  The Company has master netting arrangements with certain of its counterparties, which permit applicable obligations of the parties to be settled on a net versus gross basis.  If a right of offset exists, the fair value amounts for the derivative instruments are reported in the unaudited interim Condensed Consolidated Balance Sheet on a net basis and disclosed herein on a gross basis.

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

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Cash Flow Hedges:  (1)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive income	$	—		$	18,478
Reclassification of unrealized loss from Accumulated other comprehensive income - increase of Interest expense	—			5,615
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in Accumulated other comprehensive income	9,591			(538		)
Reclassification of unrealized gain from Accumulated other comprehensive income - increase of Operating revenues	5,536			4,655
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	18,243			—
Commodity contracts - Gathering and Processing:
Change in fair value of hedges - decrease in Operating revenues	—			7,131
Commodity contracts - Distribution:
Change in fair value - increase/(decrease) in Deferred natural gas purchases	(20,095		)	(4,279		)

	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Cash Flow Hedges:  (1)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive income	$	—		$	6,174		$	20,748
Reclassification of unrealized loss from Accumulated other comprehensive income - increase of Interest expense	—			8,085			11,166
Commodity contracts - Gathering and Processing:
Change in fair value - increase in Accumulated other comprehensive income	11,377			4,619			1,014
Reclassification of unrealized gain from Accumulated other comprehensive income	5,536			2,043			9,184
Economic Hedges:
Interest rate contracts:
Change in fair value - increase in interest expense	19,709			—			—
Commodity contracts - Gathering and Processing:
Change in fair value of other hedges - decrease in Operating revenues	—			50			23,648
Commodity contracts - Distribution:
Change in fair value - decrease in Deferred natural gas purchases	(20,095		)	(1,957		)	(23,772		)

⁽¹⁾  See Note 5 – Comprehensive Income (Loss) for related income tax amounts.

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Derivative Instrument Contingent Features

Certain of the Company’s derivative instruments contain provisions that require the Company’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies.  If the Company’s debt were to fall below investment grade, the Company would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require the Company to post collateral for certain of the derivative instruments.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at June 30, 2012 was $10.0 million.

10. FAIR VALUE MEASUREMENT:

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

	Fair Value as of		Fair Value Measurements at June 30, 2012 Using Fair Value Hierarchy
	June 30, 2012		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	14,890	$	—	$	14,890	$	—
Total	$	14,890	$	—	$	14,890	$	—
Liabilities:
Commodity derivatives	$	22,564	$	—	$	22,564	$	—
Interest-rate swap derivatives	84,746		—		84,746		—
Total	$	107,310	$	—	$	107,310	$	—

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

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

11. COMMITMENTS AND CONTINGENCIES:

Environmental Matters

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

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Environmental Remediation

Transportation and Storage Segment

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

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

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

Gathering and Processing Segment

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

Distribution Segment

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

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

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

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

Environmental Remediation Liabilities

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

	Successor		Predecessor
	June 30, 2012		December 31, 2011
Current	$	3,604	$	9,353
Noncurrent	26,246		11,635
Total environmental liabilities	$	29,850	$	20,988

Litigation and Other Claims

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

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

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

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Compliance Orders from the New Mexico Environmental Department

SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities.  The NMED has issued amended compliance orders (COs) and proposed penalties for alleged violations at Jal #4 in the amount of $0.5 million and at Jal #3 in the amount of $5.5 million.  Hearings on the COs were delayed until September 2012 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.

FGT Phase VIII Expansion.  FGT Phase VIII Expansion project was placed in-service on April 1, 2011, at an approximate cost of $2.5 billion, including capitalized equity and debt costs. To date, FGT has entered into long-term firm transportation service agreements with shippers for 25-year terms accounting for approximately 74% of the available expansion capacity.

In 2011, CrossCountry and Citrus' other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments.  The contributions are related to the costs of FGT's Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to $150 million. The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5%. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs. 

FGT Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGT's mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $82.7 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGT's pipeline without the consent of FGT although FGT would be required to relocate the pipeline if it did not provide such consent. While FGT would seek reimbursement of any costs associated with relocation of its pipeline in connection with an FDOT project, FGT may not be successful in obtaining such reimbursement and, as such, could be required to bear the cost of such relocation. In any such instance, FGT would seek recovery of the reimbursement costs in rates. The judge also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. Briefing to the Florida Fourth District Court of Appeals is complete. The Florida Fourth District Court of Appeals granted a request by the FDOT to expedite the appeal. Oral argument was held March 7, 2012. Amounts ultimately received would primarily reduce FGT's property, plant and equipment costs.

Litigation Relating to the Merger with ETE

On June 21, 2011, a putative class action lawsuit captioned Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, was filed in the 333^rd Judicial District Court of Harris County, Texas.  The petition named as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The plaintiff alleged that the defendants breached their fiduciary duties to Southern Union’s stockholders or aided and abetted breaches of fiduciary duties in connection with the Merger.  The petition alleged that the Merger involves an unfair price and an inadequate sales process and that defendants entered into the transaction to benefit themselves personally.  The petition sought injunctive relief, including an injunction of the Merger, attorneys’ and other fees and costs, indemnification and other relief.

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

On June 28, 2011, and August 19, 2011, amended petitions were filed in the Magda and Jaroslawicz actions, respectively, naming the same defendants and alleging that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of

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fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  The two Texas cases have been consolidated with the following style: In re:  Southern Union Company; Cause No. 2011-37091, in the 333^rd Judicial District Court of Harris County, Texas.  On October 21, 2011, the court denied ETE’s October 13, 2011 motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery (described below).

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

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

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

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

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

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

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

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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.

On November 28, 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), ETE and the Boards of Directors of ETP, ETP GP, and ETP LLC (collectively, the ETE Defendants).  The petition also named Southern Union as a defendant.  On January 6, 2012, the plaintiff in the Garrett Trust action filed an amended petition naming the same defendants.  On February 27, 2012, the plaintiff in the Garrett Trust action filed a second amended petition naming the same defendants.  In these petitions, the plaintiff alleges that the ETE 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 second amended petition alleges that the Citrus Merger, among other things, involves an unfair price and an unfair process and that the Directors of ETP, ETP GP, and ETP LLC failed to adequately evaluate the transaction.  The second petition also alleges that the Directors of ETP, ETP GP, and ETP LLC failed to, among other things, adequately evaluate the AmeriGas Transaction.  The second 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 second amended petition asserts claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the individual defendants, ETP GP, and ETP LLC.  The second amended complaint 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 second 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 individual defendants, ETP GP, and ETP LLC 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.

On March 6, 2012, the Garrett Trust action was transferred to the 157^th Judicial District Court of Harris County, Texas.  Trial in the Garrett Trust action has been set for January 14, 2013.

Mercury Release

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

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

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

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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.

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 June 30, 2012 and December 31, 2011, the Company recorded litigation and other claim-related accrued liabilities of $10.1 million and $28.3 million, respectively.  Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as probable or reasonably possible that would require disclosure in the financial statements.

Other Commitments and Contingencies

Regulation and Rates.  See Note 13 – Regulation and Rates 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 ten tons per year of any one Hazardous Air Pollutant (HAP) or twenty-five tons per year of all HAPs) and engines less than 500 horsepower at Major Sources (sources that emit ten tons per year or more of any one HAP or twenty-five 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 seventy-five parts per billion (ppb) with compliance anticipated in 2013 to 2015.  In January 2010, the EPA proposed lowering the standard to sixty to seventy ppb in lieu of the seventy-five 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 seventy-five ppb ozone standard established in 2008.

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

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

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

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

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 – Description of Business 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 six months ended June 30, 2012 and 2011.

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

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

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

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

	Successor		Predecessor
	Three months ended June 30, 2012		Three months ended June 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	185,216	$	189,760
Gathering and Processing	197,476		328,515
Distribution	86,220		109,076
Total segment operating revenues	468,912		627,351
Corporate and other activities	3,558		4,256
	$	472,470	$	631,607

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012		Period from January 1, 2012 to March 25, 2012		Six months ended June 30, 2011
Operating revenues from external customers:
Transportation and Storage	$	198,692	$	193,921	$	392,054
Gathering and Processing	216,833		246,463		552,167
Distribution	94,505		190,499		425,649
Total segment operating revenues	510,030		630,883		1,369,870
Corporate and other activities	2,152		2,766		8,559
	$	512,182	$	633,649	$	1,378,429

	Successor			Predecessor
	Three months ended June 30, 2012			Three months ended June 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	115,919		$	203,368
Gathering and Processing	22,362			39,473
Distribution	23,314			12,027
Corporate and other activities	637			(1,044		)
Total Segment Adjusted EBITDA	162,232			253,824
Depreciation and amortization	(74,476		)	(59,295		)
Unrealized gains on unhedged derivative activities	—			331
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(4,860		)	(2,700		)
Other, net	175			224
Proportionate share of unconsolidated investments' interest, depreciation and allowance for equity funds used during construction	(3,185		)	(52,090		)
Interest expense	(57,303		)	(54,933		)
Earnings before income taxes	22,583			85,361
Income tax expense	(10,858		)	(25,588		)
Net earnings	$	11,725		$	59,773

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	Successor			Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012			Period from January 1, 2012 to March 25, 2012			Six months ended June 30, 2011
Segment Adjusted EBITDA:
Transportation and Storage	$	82,644		$	185,706		$	370,120
Gathering and Processing	10,859			25,338			60,206
Distribution	13,446			33,554			44,304
Corporate and other activities	(1,406		)	(18,845		)	1,185
Total Segment Adjusted EBITDA	105,543			225,753			475,815
Depreciation and amortization	(79,199		)	(56,544		)	(118,622		)
Unrealized losses on unhedged derivative activities	—			—			(14,413		)
Net gain on curtailment of OPEB plans	15,332			—			—
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(4,860		)	(1,350		)	(4,654		)
Other, net	191			284			366
Proportionate share of unconsolidated investments' interest, depreciation and allowance for equity funds used during construction	(3,181		)	(44,948		)	(63,323		)
Interest expense	(61,684		)	(50,407		)	(110,504		)
Earnings (loss) before income taxes	(27,858		)	72,788			164,665
Income tax benefit (expense)	1,076			(22,871		)	(44,230		)
Net earnings (loss)	$	(26,782	)	$	49,917		$	120,435

	Successor		Predecessor
	June 30, 2012		December 31, 2011
Total assets:
Transportation and Storage	$	5,755,369	$	5,288,967
Gathering and Processing	2,805,884		1,742,516
Distribution	1,245,794		1,075,253
Total segment assets	9,807,047		8,106,736
Corporate and other activities	90,401		164,123
Total assets	$	9,897,448	$	8,270,859

	Successor		Predecessor
	Three months ended June 30, 2012		Three months ended June 30, 2011
Expenditures for long-lived assets:
Transportation and Storage	$	32,676	$	28,911
Gathering and Processing	34,930		20,903
Distribution	14,231		13,447
Total segment expenditures for long-lived assets	81,837		63,261
Corporate and other activities	841		1,321
Total expenditures for long-lived assets	$	82,678	$	64,582

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Related cash impact includes the net reduction in capital accruals totaling $0.2 million and $10.4 million for the three months ended June 30, 2012 and 2011, respectively.

	Successor		Predecessor
	Period from Acquisition (March 26, 2012) to June 30, 2012		Period from January 1, 2012 to March 25, 2012		Six months ended June 30, 2011
Expenditures for long-lived assets:
Transportation and Storage	$	34,205	$	21,047	$	39,169
Gathering and Processing	34,930		42,698		56,513
Distribution	14,231		7,075		20,409
Total segment expenditures for long-lived assets	83,366		70,820		116,091
Corporate and other activities	841		952		1,904
Total expenditures for long-lived assets	$	84,207	$	71,772	$	117,995

Related cash impact includes the net reduction in capital accruals totaling $0.5 million, $13.7 million and $26.0 million for the Successor and Predecessor periods in 2012 and the six months ended June 30, 2011, respectively.

13. REGULATION AND RATES:

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

On July 26, 2012, Trunkline filed to abandon by sale to an affiliate of underutilized loop piping facilities.  This transfer is subject to FERC approval, and the Company expects several parties to intervene and participate in this filing.

In November 2011, FERC commenced an audit of PEPL to evaluate its compliance with the Uniform System of Accounts as prescribed by FERC, annual and quarterly financial reporting to FERC, reservation charge crediting policy and record retention.  The audit is related to the period from January 1, 2010 through December 31, 2011 and is estimated to take approximately one year to complete.

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

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

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

AND RESULTS OF OPERATIONS

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

INTRODUCTION

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

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is Segment Adjusted EBITDA.  For additional information related to the Company’s use of Segment Adjusted EBITDA as its primary financial measure for its reportable segments, see Part I, Item I. Financial Statements (Unaudited), Note 12 – Reportable Segments.

The Merger, which was completed on March 26, 2012, was accounted for by ETE using business combination accounting.  By the application of "push-down" accounting, the Company allocated the purchase price paid by ETE to its assets, liabilities and equity as of the acquisition date based on preliminary estimates.  Accordingly, the successor financial statements reflect a new basis of accounting and predecessor and successor period financial results (separated by a heavy black line) are presented, but are not comparable.  The results of operations reported below are presented on a combined predecessor and successor basis since results for the matching prior year stub periods are not available.  Assets acquired and liabilities assumed are recorded at their estimated fair value and are subject to further assessment and adjustment pending further review of the assets acquired and liabilities assumed.

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

The results of operations for the combined six-month period reflect certain merger-related expenses, which are not expected to have a continuing impact on the results going forward, and those amounts are discussed in the segments results below.

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

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

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
							Combined
Segment Adjusted EBITDA:
Transportation and storage segment	$	115,919		$	203,368		$	268,350		$	370,120
Gathering and processing segment	22,362			39,473			36,197			60,206
Distribution segment	23,314			12,027			47,000			44,304
Corporate and other activities	637			(1,044		)	(20,251		)	1,185
Total Segment Adjusted EBITDA	162,232			253,824			331,296			475,815
Depreciation and amortization	(74,476		)	(59,295		)	(135,743		)	(118,622		)
Unrealized gains (losses) on nonhedged derivative activities	—			331			—			(14,413		)
Interest expense	(57,303		)	(54,933		)	(112,091		)	(110,504		)
Income tax expense	(10,858		)	(25,588		)	(21,795		)	(44,230		)
Non-cash equity-based compensation, accretion expense and amortization of regulatory assets	(4,860		)	(2,700		)	(6,210		)	(4,654		)
Net gain on curtailment of OPEB plans	—			—			15,332			—
Other, net	175			224			475			366
Proportionate share of unconsolidated investments' interest, depreciation and allowance for funds used during construction	(3,185		)	(52,090		)	(48,129		)	(63,323		)
Net earnings	$	11,725		$	59,773		$	23,135		$	120,435

Three months ended June 30, 2012 versus three months ended June 30, 2011.  The Company's $48.0 million decrease in Net earnings was primarily due to:

• Lower earnings from unconsolidated investments of $24.4 million primarily due to the Company's contribution of its unconsolidated investment in Citrus to ETP on March 26, 2012;

• A decrease of $14.5 million in gross margin for the Gathering and Processing segment, as discussed in Business Segment Results below; and

• Higher depreciation expense of $15.2 million primarily due to the step-up of property, plant and equipment resulting from the Merger; offset by

• Lower federal and state income tax expense of $14.7 million primarily due lower pretax earnings offset by the impact of lower tax expense due to the dividend received deduction in 2011.

Six months ended June 30, 2012 versus six months ended June 30, 2011.  The Company's $97.3 million decrease in Net earnings was primarily due to:

• The impact of $70.6 million of Merger-related employee severance expenses included in Segment Adjusted EBITDA, partially offset by a $15.3 million other postretirement employee benefit plan curtailment gain;

• Lower earnings from unconsolidated investments of $34.9 million primarily due to the Company's contribution of its unconsolidated investment in Citrus to ETP on March 26, 2012; and

• Higher depreciation expense of $17.1 million primarily due to the step-up of property, plant and equipment resulting from the Merger; offset by

• Lower federal and state income tax expense of $22.4 million primarily due lower pretax earnings offset by the impact of lower tax expense due to the dividend received deduction in 2011 and the non-deductible parachute payments resulting from the Merger-related employee severance expenses.

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Interest Expense

Three months ended June 30, 2012 versus three months ended June 30, 2011.  Interest expense was $2.4 million higher primarily due to an increase of $18.2 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) and $1.8 million in interest on the Note payable to ETE, which was issued in March 2012. These increases were partially offset by decreased amortization expense of $9.4 million primarily due to the fair value step-up of debt resulting from the Merger, and lower interest expense of $6.5 million related to the repayment of the $465 million Term Loan and the $250 million Term Loan in March 2012 and the refinancing of the $455 million term loan in February 2012.

Six months ended June 30, 2012 versus six months ended June 30, 2011. Interest expense was $1.6 million higher primarily due to an increase of $19.7 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) and $1.9 million in interest on the Note payable with ETE, which was issued in March 2012. These increases were partially offset by decreased amortization expense of $9.2 million primarily due to the fair value step-up of debt resulting from the Merger, and lower interest expense of $7.2 million related to the repayment of the $465 million Term Loan and the $250 million Term Loan in March 2012 and the refinancing of the $455 million term loan in February 2012.

Federal and State Income Taxes

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
							Combined
Income tax expense	$	10,858		$	25,588		$	21,795		$	44,230
Effective tax rate	48		%	30		%	49		%	27		%

Three months ended June 30, 2012 versus three months ended June 30, 2011.   The $14.7 million decrease in federal and state income tax expense was primarily due to lower pretax earnings offset by the impact of lower income tax expense of $6.7 million due to the dividend received deduction for the anticipated receipt of dividends associated with earnings from the Company's unconsolidated investment in Citrus for 2011 and higher income tax expense of $1.7 million due to non-deductible parachute payments resulting from the Merger-related employee severance expenses.

Six months ended June 30, 2012 versus six months ended June 30, 2011. The $22.4 million decrease in federal and state income tax expense was primarily due to lower pretax earnings offset by the impact of lower income tax expense of $13.4 million due to the dividend received deduction for the anticipated receipt of dividends associated with earnings from the Company's unconsolidated investment in Citrus for 2011 and higher income tax expense of $3.5 million due to non-deductible parachute payments resulting from the Merger-related employee severance expenses.

Business Segment Results

Transportation and Storage Segment

The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services.  The Transportation and Storage segment’s operations, conducted through Panhandle and, through March 26, 2012 (the date of the Citrus Merger), Florida Gas, are regulated as to rates and other matters by FERC. Demand for natural gas transmission services on Panhandle’s pipeline system is seasonal, with the highest throughput and a higher portion of annual total operating revenues and Segment Adjusted EBITDA occurring in the traditional winter heating season, which occurs during the first and fourth calendar quarters.  Florida Gas’ pipeline system experiences the highest throughput in the traditional summer cooling season during the second and third calendar quarters, primarily due to increased natural gas-fired electric generation loads.  See Item 1.  Financial Statements (Unaudited), Note 3 – ETE Merger for information related to the Citrus Merger.

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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.

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

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
							Combined
Operating revenues (1)	$	185,216		$	189,760		$	392,613		$	392,054
Operating, maintenance and general, net of non-cash compensation expense, accretion and gain on curtailment	(63,710		)	(54,865		)	(170,235		)	(118,191		)
Taxes other than on income and revenues	(9,154		)	(8,436		)	(18,592		)	(17,741		)
Adjusted EBITDA related to unconsolidated investments	3,567			76,909			64,563			113,998
Segment Adjusted EBITDA	$	115,919		$	203,368		$	268,349		$	370,120
Panhandle natural gas volumes transported (TBtu): (2)
PEPL	131			128			292			299
Trunkline	173			182			362			377
Sea Robin	21			34			43			68

⁽¹⁾  Reservation revenues comprised 89 percent and 90 percent of total operating revenues in the 2012 and 2011 periods, respectively.

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

Three months ended June 30, 2012 versus three months ended June 30, 2011.  The decrease in Transportation and Storage Segment Adjusted EBITDA was primarily due to lower contributions from Panhandle totaling $14.1 million and lower Segment Adjusted EBITDA of $73.3 million due to the Company's contribution of its unconsolidated investment in Citrus to ETP on March 26, 2012.

Panhandle's $14.1 million decrease in Segment Adjusted EBITDA was primarily due to:

• Higher operating, maintenance and general expenses, net of non-cash amounts, including compensation expense, accretion and gain on curtailment, of $8.8 million primarily attributable to reduced legal expenses in the 2011 period related to the settlement of certain litigation with several contractors related to the Company's East End project; and

• Lower operating revenues of $4.5 million primarily due to lower reservation revenue resulting primarily from contract restructurings in the fourth quarter of 2011, partially offset by higher parking revenues attributable to market conditions.

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Six months ended June 30, 2012 versus six months ended June 30, 2011.  The decrease in Transportation and Storage Segment Adjusted EBITDA was primarily due to lower contributions from Panhandle totaling $52.4 million and lower Segment Adjusted EBITDA of $49.4 million due to the Company's contribution of its unconsolidated investment in Citrus to ETP on March 26, 2012.

Panhandle's $52.4 million decrease in Segment Adjusted EBITDA was primarily due to:

• Higher operating, maintenance and general expenses, net of non-cash amounts, of $52.0 million in 2012 versus 2011 primarily attributable to the impact in 2012 of Merger-related employee severance expenses of $42.6 million reduced by legal expenses of $9.4 million in the 2011 period related to the settlement of certain ligation with several contractors related to the Company's East End projects.

See Part I, Item 1. Financial Statements (Unaudited), Note 3 - ETE Merger for more information.

Gathering and Processing Segment

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

The majority of SUGS’ gross margin is derived from the sale of NGL and natural gas equity volumes and fee-based services.  The prices of NGL and natural gas are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of factors beyond the Company’s control.  The Company monitors these risks and manages the associated commodity price risk using both economic and accounting hedge derivative instruments.  For additional information related to the Company’s commodity price risk management, see Part I, Item 1. Financial Statements (Unaudited), Note 9 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment.

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
							Combined
Operating revenues	$	197,476		$	328,515		$	463,296		$	552,167
Cost of natural gas and other energy (1)	(149,783		)	(266,306		)	(359,622		)	(459,500		)
Gross margin (2)	47,693			62,209			103,674			92,667
Unrealized (gain) loss on commodity risk management activities	—			(331		)	—			14,413
Operating, maintenance and general, excluding non-cash compensation expense and accretion	(23,597		)	(20,779		)	(63,761		)	(43,318		)
Taxes other than on income and revenues	(1,694		)	(1,466		)	(3,614		)	(3,726		)
Adjusted EBITDA related to unconsolidated investments	(40		)	(160		)	(102		)	170
Segment Adjusted EBITDA	$	22,362		$	39,473		$	36,197		$	60,206
Operating Information:
Volumes:
Avg natural gas processed (MMBtu/d)	463,059			431,453			457,533			402,978
Avg NGL produced (gallons/d)	1,662,547			1,557,025			1,644,446			1,414,597
Avg natural gas wellhead volumes (MMBtu/d)	483,083			505,238			493,196			478,618
Natural gas sales (MMBtu)	20,009,975			18,031,648			39,871,182			34,635,292
NGL sales (gallons)	159,841,353			186,343,102			337,258,519			322,661,727
Average Pricing:
Realized natural gas ($/MMBtu)  (3)	$	2.20		$	4.19		$	2.33		$	4.12
Realized NGL ($/gallon)  (3)	0.91			1.35			1.05			1.29
Natural Gas Daily WAHA ($/MMBtu)	2.22			4.24			2.31			4.18
Natural Gas Daily El Paso ($/MMBtu)	2.19			4.17			2.29			4.13
Estimated plant processing spread ($/gallon)	0.74			0.97			0.85			0.91

⁽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.

Three months ended June 30, 2012 versus three months ended June 30, 2011.  The decrease in Gathering and Processing Segment Adjusted EBITDA was primarily due to:

• Lower gross margin of $14.5 million as the result of lower operating revenues of $131.0 million and lower cost of gas and other energy of $116.5 million primarily attributable to lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $2.20 per MMBtu and $0.91 per gallon in the 2012 period versus $4.19 per MMBtu and $1.35 per gallon in the 2011 period, respectively; and

• Higher operating, maintenance and general expenses, net of non-cash compensation expense and accretion, of $2.8 million primarily due to operating costs associated with new facilities placed in service in the 2012 period.

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Six months ended June 30, 2012 versus six months ended June 30, 2011. The decrease in Gathering and Processing Segment Adjusted EBITDA was primarily due to the net impact of the following items:

• Higher gross margin of $11.0 million, as the result of lower operating revenues of $88.9 million offset by a decrease in cost of gas and other energy of $99.9 million, primarily attributable to (i) higher 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 offsetting 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 $2.33 per MMBtu and $1.05 per gallon in the 2012 period versus $4.12 per MMBtu and $1.29 per gallon in the 2011 period, respectively, and (iii) the impact of an unrealized loss on commodity risk management activities of $14.4 million in the 2011 period (which was added back for purposes of calculating Segment Adjusted EBITDA in the table above);

• Higher operating, maintenance and general expenses, net of non-cash compensation expense and accretion, of $20.4 million primarily due to Merger-related employee severance expenses in 2012 of $16.1 million.

Distribution Segment

The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts through the Company’s Missouri Gas Energy and New England Gas Company operating divisions, respectively.  The Distribution segment’s operations are regulated by the public utility regulatory commissions of the states in which each operates.  The Distribution segment’s operations have historically been sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues (which include pass-through gas purchase costs that are seasonally impacted) and Segment Adjusted EBITDA occurring in the traditional winter heating season during the first and fourth calendar quarters.  Most of Missouri Gas Energy’s revenues are based on a distribution rate structure that eliminates the impact of weather and conservations.  For additional information related to rate matters within the Distribution segment, see Part I,Item 1. Financial Statements (Unaudited), Note 13 – Regulation and Rates – Missouri Gas Energy and New England Gas Company.

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
							Combined
Net operating revenues  (1)	$	56,841		$	55,633		$	127,423		$	123,472
Operating, maintenance and general expenses, excluding non-cash compensation expense and amortization of regulatory assets	(30,034		)	(41,148		)	(73,467		)	(73,242		)
Taxes other than on income and revenues	(3,493		)	(2,458		)	(6,956		)	(5,926		)
Segment Adjusted EBITDA	$	23,314		$	12,027		$	47,000		$	44,304
Operating Information:
Natural gas sales volumes (MMcf)	5,037			6,401			27,117			39,820
Natural gas transported volumes (MMcf)	6,216			4,860			16,502			14,777
Weather – Degree Days: (2)
Missouri Gas Energy service territories	242			445			2,141			3,401
New England Gas Company service territories	599			664			2,908			3,585

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

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

Three months ended June 30, 2012 versus three months ended June 30, 2011.  The increase in Segment Adjusted EBITDA was primarily due to decreases in operating, maintenance and general expenses, net of non-cash amounts, of $11.1 million primarily due to a decrease of $5.9 million in uncollectible accounts as a result of lower gas costs and energy assistance payments, as well as other changes in operating, maintenance and general expenses between periods.

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The Company has benefited from various federal and state governmental programs that have provided home energy assistance to low income customers. During the three months ended June 30, 2012, the Company received, through grants made on behalf of customers, funding from these agencies totaling $1.0 million, which served to reduce the related delinquent accounts receivable balances. If these programs were discontinued or the related funding was significantly reduced and the customers' ability to pay had not changed, the Company would expect that bad debt expense in the Distribution segment would correspondingly increase.

Six months ended June 30, 2012 versus six months ended June 30, 2011. The increase in Segment Adjusted EBITDA was primarily due to higher net operating revenues of at New England Gas Company primarily resulting from the impact of new customer rates effective April 1, 2011.

The Company has benefited from various federal and state governmental programs that have provided home energy assistance to low income customers. During the six months ended June 30, 2012, the Company received, through grants made on behalf of customers, funding from these agencies totaling $3.7 million, which served to reduce the related delinquent accounts receivable balances. If these programs were discontinued or the related funding was significantly reduced and the customers’ ability to pay had not changed, the Company would expect that bad debt expense in the Distribution segment would correspondingly increase.

Corporate and Other Activities

Three months ended June 30, 2012 versus three months ended June 30, 2011.  The increase in Segment Adjusted EBITDA of $1.7 million was primarily due to the impact of legal and other outside service costs of $3.1 million in 2011 attributable to Merger-related expenses.

Six months ended June 30, 2012 versus six months ended June 30, 2011. The decrease in Segment Adjusted EBITDA of $21.4 million was primarily due to increased Merger-related expenses of $16.0 million.

See Item 1. Financial Statements (Unaudited), Note 3 - ETE Merger for additional information related to the Company's merger with ETE.

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 June 30, 2012.

Changes in Internal Control over Financial Reporting

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

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

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PART II.  OTHER INFORMATION

ITEM 1.   Legal Proceedings.

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in Part I, Item 1. Financial Statements (Unaudited), Note 11 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Item 8.  Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2011.

Southern Union is subject to federal and state requirements for the protection of the environment, including those for the discharge of hazardous materials and remediation of contaminated sites.  As a result, Southern Union is a party to or has its property subject to various other lawsuits or proceedings involving environmental protection matters.  For information regarding these matters, see Part I, Item 1. Financial Statements (Unaudited), Note 11 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q and in the Item 8.  Financial Statements and Supplementary Data, Note 14 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2011.

ITEM 1A.  Risk Factors.

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

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

On March 26, 2012, pursuant to the terms of the Merger Agreement, Merger Sub merged with and into the Company with the Company surviving as an indirect wholly-owned subsidiary of ETE and the Company issued 940 shares of common stock to ETE to evidence ETE’s ownership of the Company as a result of the consummation of the Merger.

The issuance described above was effected in reliance on the exemptions for sales of securities not involving a public offering, as set forth in Section 4(2) of the Securities Act, based on the issuance being a private offering in connection with the initial capitalization of the Company.  There were no underwriters involved in connection with the issuance of these securities.

ITEM 3.  Defaults Upon Senior Securities.

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.  Mine Safety Disclosures.

N/A

ITEM 5.  Other Information.

None.

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ITEM 6.  Exhibits.

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

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.

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SIGNATURE

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

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

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