10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C.  20549

____________________________

FORM 10-Q

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended

June 30, 2011

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.)
5444 Westheimer Road Houston, Texas (Address of principal executive offices)	77056-5306 (Zip Code)

Registrant's telephone number, including area code:  (713) 989-2000

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 RNo £

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 RNo £

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 R    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 R

The number of shares of the registrant's Common Stock outstanding on August 5, 2011 was 124,745,576.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

June 30, 2011

Table of Contents

PART I.  FINANCIAL INFORMATION:                                                                                                                                           Page(s)

     Glossary.                                                                                                                                                                                                    1

     ITEM 1.  Financial Statements (Unaudited):

          Condensed consolidated statement of operations.                                                                                                                 2

          Condensed consolidated balance sheet.                                                                                                                                        3

          Condensed consolidated statement of cash flows.                                                                                                                 5

          Condensed consolidated statement of stockholders’ equity and comprehensive income.                                              6

          Notes to condensed consolidated financial statements.                                                                                                       7

     ITEM 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.                          34

     ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk.                                                                               48

     ITEM 4.  Controls and Procedures.                                                                                                                                                   51

PART II.  OTHER INFORMATION

     ITEM 1.  Legal Proceedings.                                                                                                                                                              53

     ITEM 1A.  Risk Factors.                                                                                                                                                                     53

     ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.                                                                              55

     ITEM 3.  Defaults Upon Senior Securities.                                                                                                                                56

     ITEM 4.  Reserved.                                                                                                                                                                             56

     ITEM 5.  Other Information.                                                                                                                                                               56

     ITEM 6.  Exhibits.                                                                                                                                                                                56

     SIGNATURES.                                                                                                                                                                                     61

GLOSSARY

The abbreviations, acronyms and industry terminology used in this Quarterly Report 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

EBIT                                                                                                                       Earnings before interest and taxes

EITR                                                                                                                       Effective income tax rate

EPA                                                                                                                        United States Environmental Protection Agency

ETE                                                                                                                         Energy Transfer Equity, L.P.

Exchange Act                                                                                                       Securities Exchange Act of 1934

FERC                                                                                                                      Federal Energy Regulatory Commission

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

Florida Gas                                                                                                            Florida Gas Transmission Company, LLC

GAAP                                                                                                                    Accounting principles generally accepted in the United States of America

Gallons/d                                                                                                               Gallons per day

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

Panhandle                                                                                                            Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCBs                                                                                                                     Polychlorinated biphenyls

PEPL                                                                                                                     Panhandle Eastern Pipe Line Company, LP

PRPs                                                                                                                     Potentially responsible parties

RCRA                                                                                                                   Resource Conservation and Recovery Act

SARs                                                                                                                    Stock appreciation rights

Sea Robin                                                                                                            Sea Robin Pipeline Company, LLC

SEC                                                                                                                       United States Securities and Exchange Commission

Sigma                                                                                                                    Sigma Acquisition Corporation

Southern Union                                                                                                  Southern Union Company

SPCC                                                                                                                    Spill Prevention, Control and Countermeasure

SUGS                                                                                                                    Southern Union Gas Services

TBtu                                                                                                                     Trillion British thermal units

TCEQ                                                                                                                   Texas Commission on Environmental Quality

Trunkline                                                                                                             Trunkline Gas Company, LLC

Trunkline LNG                                                                                                    Trunkline LNG Company, LLC

1

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands, except per share amounts)
Operating revenues (Note 13)	$	631,607		$	573,096		$	1,378,429		$	1,332,090
Operating expenses
Cost of natural gas and other energy		315,575			246,626			741,207			685,635
Operating, maintenance and general		123,858			118,723			244,852			232,608
Depreciation and amortization		59,295			57,559			118,622			112,753
Revenue-related taxes		5,200			4,806			22,567			21,848
Taxes, other than on income and revenues		12,657			13,638			28,127			28,224
Total operating expenses		516,585			441,352			1,155,375			1,081,068
Operating income		115,022			131,744			223,054			251,022
Other income (expenses)
Interest expense		(54,933	)		(55,436	)		(110,504	)		(106,312	)
Earnings from unconsolidated investments		25,048			27,542			51,749			46,120
Other, net		224			(352	)		366			(63	)
Total other expenses, net		(29,661	)		(28,246	)		(58,389	)		(60,255	)
Earnings before income taxes		85,361			103,498			164,665			190,767
Federal and state income tax expense (Note 9)		25,588			28,609			44,230			59,418
Net earnings		59,773			74,889			120,435			131,349
Preferred stock dividends		-			(2,170	)		-			(4,341	)
Loss on extinguishment of preferred stock		-			(3,295	)		-			(3,295	)
Net earnings available for common stockholders	$	59,773		$	69,424		$	120,435		$	123,713
Net earnings available for common stockholders per share
Basic	$	0.48		$	0.56		$	0.97		$	0.99
Diluted	$	0.47		$	0.55		$	0.96		$	0.99
Cash dividends declared on common stock per share	$	0.15		$	0.15		$	0.30		$	0.30
Weighted average shares outstanding (Note 4)
Basic		124,712			124,474			124,685			124,445
Diluted		125,875			125,244			125,737			125,202

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

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS
	June 30,		December 31,
	2011		2010
	(In thousands)
Current assets
Cash and cash equivalents	$	3,013	$	3,299
Accounts receivable
net of allowances of $4,467 and $3,321, respectively		262,293		310,006
Accounts receivable – affiliates		7,863		10,747
Inventories		174,040		226,875
Deferred natural gas purchases		13,396		85,138
Natural gas imbalances - receivable		72,006		52,141
Prepayments and other assets		70,241		67,535
Total current assets		602,852		755,741
Property, plant and equipment
Plant in service		7,020,306		6,957,989
Construction work in progress		165,126		120,264
		7,185,432		7,078,253
Less accumulated depreciation and amortization		1,487,919		1,373,794
Net property, plant and equipment		5,697,513		5,704,459
Deferred charges
Regulatory assets		63,022		66,216
Deferred charges		64,731		66,929
Total deferred charges		127,753		133,145
Unconsolidated investments  (Note 5)		1,587,863		1,538,548
Goodwill		89,227		89,227
Other		84,861		17,423
Total assets	$	8,190,069	$	8,238,543

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES
	June 30,			December 31,
	2011			2010
	(In thousands)
Stockholders’ equity (Note 15)
Common stock, $1 par value; 200,000 shares authorized; 125,975
and 125,839 shares issued, respectively	$	125,975		$	125,839
Premium on capital stock		1,927,356			1,920,622
Less treasury stock: 1,240 and 1,230 shares, respectively, at cost		(30,809	)		(30,532	)
Less common stock held in trust: 573 and 597 shares, respectively		(10,543	)		(10,857	)
Deferred compensation plans		10,543			10,857
Accumulated other comprehensive loss		(51,507	)		(40,157	)
Retained earnings		634,236			551,210
Total stockholders' equity		2,605,251			2,526,982
Long-term debt obligations  (Note 7)		2,705,534			3,520,906
Total capitalization		5,310,785			6,047,888
Current liabilities
Long-term debt due within one year  (Note 7)		816,272			1,083
Notes payable (Note 7)		195,479			297,051
Accounts payable and accrued liabilities		198,357			218,531
Federal, state and local taxes payable		35,824			35,235
Accrued interest		37,397			37,464
Natural gas imbalances - payable		152,211			178,087
Derivative instruments (Note 10 and 11)		56,200			67,026
Other		124,997			137,221
Total current liabilities		1,616,737			971,698
Deferred credits		203,202			205,094
Accumulated deferred income taxes		1,059,345			1,013,863
Commitments and contingencies  (Note 12)
Total stockholders' equity and liabilities	$	8,190,069		$	8,238,543

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	120,435		$	131,349
Adjustments to reconcile net earnings to net cash flows
provided by (used in) operating activities:
Depreciation and amortization		118,622			112,753
Deferred income taxes		51,543			60,087
Provision for bad debts		9,864			9,562
Unrealized loss (gain) on commodity derivatives		14,413			(16,654	)
Share-based compensation expense		4,899			4,454
Earnings from unconsolidated investments,
adjusted for cash distributions		(50,249	)		(42,396	)
Changes in operating assets and liabilities		81,384			(16,663	)
Net cash flows provided by operating activities		350,911			242,492
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(143,902	)		(129,379	)
Loan to unconsolidated investments		(72,000	)		-
Plant retirements and other		(488	)		359
Net cash flows used in investing activities		(216,390	)		(129,020	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		4,877			(12,030	)
Issuance of long-term debt		-			857
Renewal cost for credit facilities		(2,138	)		(5,831	)
Dividends paid on common stock		(37,390	)		(37,322	)
Dividends paid on preferred stock		-			(4,341	)
Repayment of long-term debt obligation		(278	)		(140,723	)
Net change in revolving credit facilities		(101,572	)		76,095
Other		1,694			1,866
Net cash flows used in financing activities		(134,807	)		(121,429	)
Change in cash and cash equivalents		(286	)		(7,957	)
Cash and cash equivalents at beginning of period		3,299			10,545
Cash and cash equivalents at end of period	$	3,013		$	2,588

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common		Premium						Common			Deferred			Accumulated						Total
	Stock,		on			Treasury			Stock			Compen-			Other						Stock-
	$1 Par		Capital			Stock,			Held			sation			Comprehensive			Retained			holders'
	Value		Stock			at cost			In Trust			Plans			Loss			Earnings			Equity
	(In thousands)
Balance December 31, 2010	$	125,839	$	1,920,622		$	(30,532	)	$	(10,857	)	$	10,857		$	(40,157	)	$	551,210		$	2,526,982
Comprehensive income (loss):
Net earnings		-		-			-			-			-			-			120,435			120,435
Net change in other
comprehensive loss (Note 6)		-		-			-			-			-			(11,350	)		-			(11,350	)
Comprehensive income		-		-			-			-			-			-			-			109,085
Common stock dividends declared		-		-			-			-			-			-			(37,409	)		(37,409	)
Share-based compensation		-		4,899			-			-			-			-			-			4,899
Restricted stock issuances		7		(7	)		-			-			-			-			-			-
Exercise of stock options		129		1,842			(277	)		-			-			-			-			1,694
Contributions to Trust		-		-			-			(355	)		355			-			-			-
Disbursements from Trust		-		-			-			669			(669	)		-			-			-
Balance June 30, 2011	$	125,975	$	1,927,356		$	(30,809	)	$	(10,543	)	$	10,543		$	(51,507	)	$	634,236		$	2,605,251
The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 par value, is equivalent to the change in the number of shares of common stock issued.

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

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of the Companyhave been prepared pursuant to the rules and regulations of the SEC for quarterly reports on Form 10-Q.  These statements do not include all of the information and annual note disclosures required by GAAP, and should be read in conjunction with the Company’s financial statements and notes thereto for the year ended December 31, 2010, 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 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Due to the seasonal nature of the Company’s operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year.

1.  Description of Business

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.  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 also provides LNG terminalling and regasification services.  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.  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 intent to merge with ETE.

2.  New Accounting Principles

Accounting Principles Not Yet Adopted.  In June 2011, the FASB issued authoritative guidance that changes how a company may present comprehensive income.  The guidance allows entities to elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive statements and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted.  The Company does not expect the guidance to materially impact its consolidated financial statements as the guidance only requires a change in the placement of previously disclosed information.   

In May 2011, the FASB issued authoritative guidance on fair value measurements that clarifies some existing concepts, eliminates wording differences between GAAP and International Financial Reporting Standards (IFRS), and in some limited cases, changes some principles to achieve convergence between GAAP and IFRS. The guidance provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS and also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. The guidance is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact of this guidance, but does not expect it will materially impact its consolidated financial statements.

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3.  ETE Merger

On July 19, 2011, the Company entered into a Second Amended and Restated Agreement and Plan of Merger (Second Amended Merger Agreement) with ETE and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub).  The Second Amended Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by the Company, ETE and Merger Sub on June 15, 2011 as amended on July 4, 2011.  The Second Amended Merger Agreement provides for the merger of Merger Sub with and into the Company (Merger), with the Company continuing as the surviving corporation in the Merger.  As a result of the Merger, the Company will become a wholly-owned subsidiary of ETE.  The Merger is expected to close in the first quarter of 2012, subject to stockholder approval and certain other regulatory approvals.

Under the terms of the Second Amended Merger Agreement, at least 50 percent, and no more than 60 percent, of the shares of common stock of the Company issued and outstanding immediately prior to the effective time of the Merger (Outstanding Shares) will be cancelled and converted into the right to receive cash in the amount of $44.25 per Outstanding Share (subject to reduction of that amount of cash per Outstanding Share, and supplementation with ETE Common Units, in the event that holders of more than 60 percent of the Outstanding Shares elect to receive cash) and at least 40 percent, and no more than 50 percent of the Outstanding Shares will be cancelled and converted into the right to receive 1.0 ETE Common Units per Outstanding Share (subject to reduction of that number of ETE Common Units per Outstanding Share, and supplementation with cash, in the event that holders of more than 50 percent of the Outstanding Shares elect to receive ETE Common Units).

 On July 19, 2011, ETE entered into an amended and restated agreement and plan of merger (Citrus Merger Agreement) with Energy Transfer Partners , L.P. (ETP). Pursuant to the Citrus Merger Agreement, immediately prior to the effective time of the Merger, ETE will assign and Southern Union will assume the benefits and obligations of ETE under the Citrus Merger Agreement. Under the Citrus Merger Agreement, it is anticipated that Southern Union will cause the contribution to ETP of its 50 percent interest in Citrus Corp., which owns 100 percent of Florida Gas and is currently jointly owned by Southern Union and El Paso Corporation (Citrus Merger). The Citrus Merger will be effected through the merger of CrossCountry Energy, LLC, a Delaware limited liability company and wholly-owned subsidiary of Southern Union that indirectly owns a 50 percent interest in Citrus Corp., with and into Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of ETP. In exchange for the interest in Citrus Corp., Southern Union will receive approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP common units, with the value of the ETP common units based on the volume-weighted average trading price for the ten consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Merger.  Immediately prior to the effective time of the Merger, Southern Union will contribute to Merger Sub the funds it receives pursuant to the Citrus Merger (not to exceed $1.45 billion) in exchange for an equity interest in Merger Sub proportionate to its deemed share, which means the fraction (i) the numerator of which is the amount, if any, contributed by Southern Union to Merger Sub pursuant to the Second Amended Merger Agreement and (ii) the denominator of which is the aggregate value of the merger consideration of the Merger, valuing the ETE common units based upon the volume weighted average price of the ETE common units for the five trading days ending on the trading day immediately preceding the effective time of the Merger.

The Second Amended Merger Agreement contains certain termination rights for the Company and ETE.  In certain circumstances, upon termination of the Second Amended Merger Agreement, the Company or ETE, as applicable: (i) will be required to pay a termination fee of $181.3 million to the other and (ii) may be obligated to pay the other’s Merger costs and expenses in an amount not to exceed $54 million.

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Consummation of the merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended Merger Agreement by the stockholders of the Company, (ii) the expiration of the waiting period applicable to the merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, which expiration occurred on July 28, 2011, (iii) the receipt of required approvals from the FERC, the MPSC and, if necessary, the MDPU, (iv) the effectiveness of an ETE registration statement on Form S-4 relating to the ETE common units to be issued in the merger, and (v) the absence of any law, injunction, judgment or ruling prohibiting or restraining the merger or making the consummation of the merger illegal.

On July 13, 2011, the Company and ETE filed a joint application with the MPSC, requesting an order from the MPSC authorizing the Company to take certain actions to allow ETE to acquire the equity interests of the Company, including its subsidiaries.  On July 11, 2011, as amended July 26, 2011, ETE filed a registration statement on Form S-4 relating to the registration of the ETE common units to be issued in the merger.

The Company has made certain customary representations and warranties and covenants in the Second Amended Merger Agreement, including without limitation covenants regarding: (i) the conduct of the business of the Company prior to the consummation of the merger, (ii) the calling and holding of a meeting of the Company’s stockholders for the purpose of obtaining its required stockholder approval and (iii) the use of reasonable best efforts to cause the merger to be consummated.

4.  Earnings per Share

Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period.  Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, increased by common stock equivalents from stock options, restricted stock and SARs.  A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table for the periods presented.

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(In thousands)
Weighted average shares outstanding - Basic		124,712		124,474		124,685		124,445
Dilutive effect of share-based compensation awards		1,163		770		1,052		757
Weighted average shares outstanding - Diluted		125,875		125,244		125,737		125,202

The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company’s common shares.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands, except per share amounts)
Options and SARs excluded			-			1,235			-			1,235
Exercise price ranges			N/A		$	24.06 - 28.48			N/A		$	24.06 - 28.48
Weighted-average market price		$	30.11		$	23.70		$	28.67		$	23.73

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5.  Unconsolidated Investments

Unconsolidated investments at June 30, 2011 and December 31, 2010 include the Company’s 50 percent investment in Citrus and investments in other entities. The Company accounts for these investments using the equity method.  The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the unaudited interim Condensed Consolidated Statement of Operations.

The following table summarizes the Company’s unconsolidated equity investments at the dates indicated.

	June 30,		December 31,
	2011		2010
	(In thousands)
Citrus  (1)	$	1,561,664		$	1,510,847
Other		26,199			27,701
	$	1,587,863		$	1,538,548

___________________

(1)  See Note 3 – ETE Merger for information regarding the Company’s intent for its ownership interest in Citrus to be merged with an ETP subsidiary.

The following table sets forth summarized financial information for the Company’s equity investments for the periods presented.

	Three Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	194,361	$	2,506	$	140,572	$	5,823
Operating income		118,716		705		77,323		3,297
Net earnings		47,173		689		46,460		3,101
	Six Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	308,246	$	5,082	$	254,711	$	11,684
Operating income		168,598		1,637		129,694		6,482
Net earnings		96,526		1,844		76,087		6,270

Citrus Dividends.  Citrus did not pay dividends to the Company during the three-month periods ended  and six-month periods ended June 30, 2011 and 2010.

10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus

Florida Gas Phase VIII Expansion.  Florida Gas’ Phase VIII Expansion project was placed in-service on April 1, 2011, at an estimated cost of approximately $2.48 billion, including capitalized equity and debt costs.  To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.

In 2011, the Company, through an indirect wholly-owned subsidiary, and Citrus’ other shareholder each made sponsor contributions of $72 million in the form of loans to Citrus.   The Company has recorded the Citrus loan in Other non-current assets on the Condensed Consolidated Balance Sheet.  The contributions are related to the costs of Florida Gas' Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each shareholder 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 percent.  Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs.   Citrus’ principal operating asset is Florida Gas, whose debt is rated Baa2 by Moody’s Investor Services, Inc. and BBB by Standard & Poors.

Florida Gas 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 Florida Gas’ 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 Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE.  On May 2, 2011, the judge issued an order entitling Florida Gas to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space.  The judge further ruled that Florida Gas 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 Florida Gas’ pipeline without the consent of Florida Gas although Florida Gas would be required to relocate the pipeline if it did not provide such consent.  He also denied all other pending post-trial motions.  The FDOT/FTE filed a notice of appeal on July 12, 2011.  Amounts ultimately received would primarily reduce Florida Gas’ property, plant and equipment costs.

On April 14, 2011 Florida Gas filed suit against the FDOT/FTE, Dragados USA and I-595 Express, LLC in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in Florida Gas easements containing the newly constructed 36-inch pipeline.  The same judge that presided over the previously discussed FDOT/FTE proceeding was assigned to the case.  Trial is expected to be set in early 2012.

11

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6.  Comprehensive Income (Loss)

The table below provides an overview of Comprehensive income (loss) for the periods presented.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands)
Net earnings	$	59,773		$	74,889		$	120,435		$	131,349
Change in fair value of interest rate hedges, net of tax of
$(6,891), $(1,308), $(7,757) and $(3,614), respectively		(11,587	)		(1,945	)		(12,991	)		(5,375	)
Reclassification of unrealized loss on interest rate hedges
into earnings, net of tax of $2,253, $2,250, $4,481
and $4,554, respectively		3,362			3,357			6,685			6,803
Change in fair value of commodity hedges, net of tax of $194,
$(390), $(365) and $9,613, respectively		344			(690	)		(649	)		17,061
Reclassification of unrealized gain on commodity hedges
into earnings, net of tax of $(1,678), $(1,830), $(3,310) and $(2,272), respectively		(2,977	)		(3,247	)		(5,874	)		(4,032	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $568, $551, $1,142
and $1,102, respectively		706			722			1,407			1,442
Change in other comprehensive income from equity
investments, net of tax of $21, $22, $43 and $44, respectively		37			35			72			71
Total other comprehensive income (loss)		(10,115	)		(1,768	)		(11,350	)		15,970
Total comprehensive income	$	49,658		$	73,121		$	109,085		$	147,319

The table below provides an overview of the components in Accumulated other comprehensive loss as of the dates indicated.

	June 30,			December 31,
	2011			2010
	(In thousands)
Interest rate hedges, net	$	(23,538	)	$	(17,232	)
Commodity hedges, net		4,005			10,528
Benefit plans:
Net actuarial loss and prior service costs, net - pensions		(30,372	)		(32,982	)
Net actuarial gain and prior service credit, net - other postretirement benefits		1,004			2,207
Equity investments, net		(2,606	)		(2,678	)
Total Accumulated other comprehensive income, net of tax	$	(51,507	)	$	(40,157	)

12

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7.  Debt Obligations

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

	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Long-Term Debt Obligations:
Southern Union:
7.60% Senior Notes due 2024	$	359,765	$	428,300	$	359,765	$	392,144
8.25% Senior Notes due 2029		300,000		377,403		300,000		332,922
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		23,558		19,500		21,473
7.20% Junior Subordinated Notes due 2066		600,000		575,280		600,000		609,743
Term Loan due 2013		250,000		252,491		250,000		249,915
Note Payable		8,019		8,019		8,297		8,297
		1,537,284		1,665,051		1,537,562		1,614,494
Panhandle:
6.05% Senior Notes due 2013		250,000		273,260		250,000		268,988
6.20% Senior Notes due 2017		300,000		346,413		300,000		322,893
8.125% Senior Notes due 2019		150,000		183,813		150,000		169,671
7.00% Senior Notes due 2029		66,305		70,068		66,305		69,911
7.00% Senior Notes due 2018		400,000		472,416		400,000		442,120
Term Loans due 2012		815,391		808,481		815,391		799,084
Net premiums on long-term debt		2,826		2,826		2,731		2,731
		1,984,522		2,157,277		1,984,427		2,075,398
Total Long-Term Debt Obligations		3,521,806		3,822,328		3,521,989		3,689,892
Credit Facilities		195,479		195,487		297,051		301,312
Total consolidated debt obligations		3,717,285	$	4,017,815		3,819,040	$	3,991,204
Less current portion of long-term debt		816,272				1,083
Less short-term debt		195,479				297,051
Total long-term debt	$	2,705,534			$	3,520,906

The fair value of the Company’s term loans and credit facilities as of June 30, 2011 and December 31, 2010 were determined using the market approach, which utilized 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.

13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The fair value of the Company’s other long-term debt as of June 30, 2011 and December 31, 2010 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. 

Interest Rate Swaps.  The Company has entered into 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 10 – Derivative Instruments and Hedging Activities – Interest Rate Contracts – Interest Rate Swaps for more information regarding these swap agreements.

Credit Facilities.  During the second quarter of 2011, the Company entered into the Seventh Amended and Restated Revolving Credit Agreement with certain banks in the amount of $550 million (2011 Revolver).  The 2011 Revolver is an amendment, restatement and refinancing of the Company’s $550 million Sixth Amended and Restated Revolving Credit Agreement (Revolver), which was otherwise scheduled to mature on May 28, 2013.  The 2011 Revolver will mature on May 20, 2016.  Borrowings under the 2011 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 2011 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 2011 Revolver at June 30, 2011 were LIBOR plus 162.5 basis points and 25 basis points, respectively.  

14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

8.  Benefits

Components of Net Periodic Benefit Cost.  The following table sets forth the components of net periodic benefit cost of the Company’s pension and postretirement benefit plans for the periods presented.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)
Service cost	$	935		$	768		$	881			$	793
Interest cost		2,525			2,509			1,446				1,409
Expected return on plan assets		(2,647	)		(2,337	)		(1,450	)			(1,269	)
Prior service cost (credit)
amortization		147			138			(453	)			(411	)
Actuarial loss (gain)
amortization		1,984			1,996			(403	)			(451	)
		2,944			3,074			21				71
Regulatory adjustment (1)		191			52			666				666
Net periodic benefit cost	$	3,135		$	3,126		$	687			$	737
	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011				2010
	(In thousands)
Service cost	$	1,870		$	1,535		$	1,761			$	1,586
Interest cost		5,050			5,019			2,892				2,819
Expected return on plan assets		(5,293	)		(4,674	)		(2,899	)			(2,311	)
Prior service cost (credit)
amortization		294			276			(906	)			(823	)
Actuarial loss (gain)
amortization		3,967			3,993			(806	)			(901	)
		5,888			6,149			42				370
Regulatory adjustment (1)		383			157			1,332				1,332
Net periodic benefit cost	$	6,271		$	6,306		$	1,374			$	1,702

________________________________

(1)   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.

15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9.  Taxes on Income

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2011				2010				2011				2010
	(In thousands)
Income tax expense		$	25,588			$	28,609			$	44,230			$	59,418
Effective tax rate			30	%			28	%			27	%			31	%

The EITR is generally lower than the U.S. federal income tax statutory rate of 35 percent primarily due to the 80 percent dividends received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated investment in Citrus.

10.  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.

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 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 will become effective on November 1, 2011.  The Company will pay interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175 percent beginning November 1, 2011. The interest rate swaps will 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 loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  There was no swap ineffectiveness during the period ended June 30, 2011.  As of June 30, 2011, the floating rate LIBOR-based portion of the interest payments commencing November 1, 2011 was exchanged for weighted average fixed rate interest payments of 3.63 percent.

16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company also has outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the LNG Holdings $455 million term loan.  These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

As of June 30, 2011, approximately $14.2 million of net after-tax gains in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Treasury Rate Locks.  As of June 30, 2011, the Company had no outstanding treasury rate locks.  However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt.  These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.  As of June 30, 2011, approximately $571,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.

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

Natural Gas Price Swaps.  As of June 30, 2011, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 8,280,000 MMBtu for the remainder of 2011 and 3,660,000 MMBtu for 2012.  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 loss and reclassified into Operating revenues in the same periods during which the forecasted natural gas sales impact earnings.  As of June 30, 2011, approximately $6 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps are expected to be amortized into 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, 2011, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 65,378,124 gallons (5,490,000 MMBtu equivalent basis) for 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 loss and reclassified into Operating revenues in the same periods during which the forecasted NGL sales impact earnings.  As of June 30, 2011, approximately $1.6 million of net after-tax losses in Accumulated other comprehensive loss related to these NGL price swaps are expected to be amortized into Operating revenues during the next twelve months.  Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Processing Spread Swaps.  As of June 30, 2011, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 4,600,000 MMBtu equivalents for the remainder of 2011.  These processing spread swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues.

17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Commodity Contracts - Distribution Segment

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

Natural Gas Price Swaps.  As of June 30, 2011, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 8,490,000 MMBtu, 14,270,000 MMBtu and 2,020,000 MMBtu for the remainder of 2011, 2012 and 2013, respectively.  These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred natural gas purchases.

18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Summary Financial Statement Information

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

	Asset Derivatives (1)				Liability Derivatives (1)
	June 30,		December 31,		June 30,		December 31,
Balance Sheet Location	2011		2010		2011		2010
	(In thousands)				(In thousands)
Cash Flow Hedges:
Interest rate contracts
Derivative instruments-liabilities	$	-	$	-	$	23,353	$	19,694
Deferred credits		-		-		11,039		4,652
Commodity contracts - Gathering and Processing:
Natural gas price swaps
Derivative instruments-liabilities	$	9,275	$	16,459	$	-	$	-
Deferred credits		230		-		-		-
NGL price swaps
Derivative instruments-liabilities		-		-		2,408		-
Deferred credits		-		-		836		-
	$	9,505	$	16,459	$	37,636	$	24,346
Economic Hedges:
Commodity contracts - Gathering and Processing:
NGL processing spread swaps
Derivative instruments-liabilities	$	-	$	-	$	26,716	$	29,057
Other derivative instruments
Prepayments and other assets		9		133		-		-
Commodity contracts - Distribution:
Natural gas price swaps
Derivative instruments-liabilities	$	100	$	234	$	13,098	$	34,968
Deferred credits		51		105		716		2,806
	$	160	$	472	$	40,530	$	66,831
Total	$	9,665	$	16,931	$	78,166	$	91,177

_____________

(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.

19

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company’s unaudited interim condensed consolidated financial statements for the periods presented.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)
Cash Flow Hedges:  (1)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive
loss, excluding tax expense effect of $6,891, $1,308, $7,757 and $3,614, respectively	$	18,478		$	3,253		$	20,748		$	8,989
Reclassification of unrealized loss from Accumulated other
comprehensive loss - increase of Interest expense, excluding tax
expense effect of $2,253, $2,250, $4,481 and $4,554 respectively		5,615			5,607			11,166			11,357
Commodity contracts - Gathering and Processing:
Change in fair value - increase/(decrease) in Accumulated other
comprehensive loss, excluding tax expense effect of $(194), $390, $365 and $(9,613), respectively		(538	)		1,080			1,014			(26,674	)
Reclassification of unrealized gain from Accumulated other
comprehensive loss - increase of Operating revenues, excluding
tax expense effect of $1,678, $1,830, $3,310 and $2,272, respectively		4,655			5,077			9,184			6,304
Economic Hedges:
Commodity contracts - Gathering and Processing:
Change in fair value of strategic hedges - (increase)/decrease in Operating revenues  (2)		7,149			(21,597	)		23,865			(14,672	)
Change in fair value of other hedges - (increase)/decrease in Operating revenues		(18	)		(375	)		(217	)		186
Commodity contracts - Distribution:
Change in fair value - decrease in Deferred natural gas purchases		(4,279	)		(23,947	)		(23,772	)		(7,707	)

_________________

(1)   See Note 6 – Comprehensive Income (Loss) for additional related information.

(2)   Includes $7.3 million and $16.8 million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2011, respectively.  Includes $9 million and $20 million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2010, respectively.  Additionally, includes a $300,000 unrealized mark-to-market gain and a $14.4 million unrealized mark-to-market loss recorded in the three-month and six-month periods ended June 30, 2011, respectively, and $22.3 million and $16.6 million of unrealized mark-to-market gains recorded in the three-month and six-month periods ended June 30, 2010, respectively.

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, 2011 was $8 million.

20

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11.  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 dates indicated.

	Fair Value			Fair Value Measurements at June 30, 2011
	as of			Using Fair Value Hierarchy
	June 30, 2011			Level 1			Level 2			Level 3
	(In thousands)
Assets:
Commodity derivatives		$	9		$	-		$	9		$	-
Long-term investments			1,027			1,027			-			-
Total		$	1,036		$	1,027		$	9		$	-
Liabilities:
Commodity derivatives		$	34,118		$	-		$	34,118		$	-
Interest-rate swap derivatives			34,392			-			34,392			-
Total		$	68,510		$	-		$	68,510		$	-

The Company’s Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.  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, 2011 or December 31, 2010.

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.

12.  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 applicable 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.

21

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

22

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other PRPs and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations.

North Attleboro MGP Site in Massachusetts (North Attleboro Site).  In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site.  Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties.  Assessment activities have recently been completed and it is estimated that the Company will spend approximately $10.6 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 Sheet.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the Condensed Consolidated Balance Sheet at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable.  The Company does not have any material environmental remediation matters assessed as reasonably possible.

	June 30,			December 31,
	2011			2010
	(In thousands)
Current		$	5,890		$	10,648
Noncurrent			15,517			11,920
Total environmental liabilities		$	21,407		$	22,568

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 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 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.

East End Project. The East End project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana.  Construction began in 2007 and was

23

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

completed in the second quarter of 2008.  PEPL sought recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project.  Certain of the contractors filed counterclaims against PEPL for alleged underpayments of approximately $18 million.  Panhandle settled with three defendants prior to trial in Harris County, Texas. Trial began on May 16, 2011 and after the fourth week of trial a settlement was reached with the last defendant, Acuren.  The various settlements resulted in the Company receiving a total of  approximately $16 million and $9 million for reimbursement of previously incurred legal expenses associated with the proceeding and project cost overruns, respectively.

Attorney General of the Commonwealth of Massachusetts Attorney General 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 current 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 legal fees charged that were passed through the recovery mechanism and whether they would qualify for a lesser, 50 percent, level of recovery.  The Company believes it has complied with all applicable requirements of the MDPU regarding its filings for cost recovery; 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.  In March, the NMED amended the consent order it filed against SUGS in 2010, removing numerous claims and adding several more.

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 333rd Judicial District Court of Harris County, Texas. The petition names as defendants the members of Southern Union’s Board, as well as Southern Union and ETE. The plaintiff alleges 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 alleges 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 seeks injunctive relief, including to enjoin 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 11th Judicial District Court of Harris County, Texas.  The petition named as defendants the members of Southern Union’s Board, Southern Union, and ETE.  The plaintiff alleges 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 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, and that defendants have failed to disclose all material information related to the merger to Southern Union stockholders. The petition seeks injunctive relief, including to enjoin the

24

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  On June 28, 2011, an amended petition was filed, 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 those alleged breaches of fiduciary duty.  The amended petition 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 defendants have failed to disclose all material information related to the merger to Southern Union stockholders.  The amended petition seeks injunctive relief, including to enjoin the merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

The plaintiffs in the two Texas cases filed a motion to appoint lead counsel and a motion for expedited discovery.  To date, no preliminary injunctions have been filed in these Texas cases.

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 names as defendants the members of Southern Union’s Board, Southern Union, and ETE. The plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the merger, and further claim that ETE aided and abetted those alleged breaches. The 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 directors should deem a competing proposal made by The Williams Companies, Inc. (Williams) to be superior. The complaint seeks compensatory damages, injunctive relief, including to enjoin 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 name as defendants the members of Southern Union’s Board, Southern Union, ETE, and Merger Sub. The plaintiffs allege 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 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 the directors must give full consideration to the Williams proposal. The complaint seeks compensatory damages, injunctive relief, including to enjoin 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 names as defendants the members of Southern Union’s Board, Southern Union, ETE, and Merger Sub. The plaintiffs allege 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 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, and that the terms of the amended merger agreement are preclusive. The complaint seeks injunctive relief, including to enjoin the merger, and an award of attorneys’ and other fees and costs, in addition to other relief.

25

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

To date, the four Delaware plaintiffs have filed no preliminary injunctions or motions to appoint lead counsel or consolidate the lawsuits.  The Company believes the allegations of all the foregoing actions lack merit and will contest them.

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 establishes reserves for litigation and other claim costs when management believes a loss is probable and reasonably estimable.  As of June 30, 2011 and December 31, 2010, the Company recorded litigation and other claim-related accrued liabilities of $28.2 million and $26.9 million, respectively. Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as reasonably possible.

Other Commitments and Contingencies

Regulation and Rates.See Note 14 – Regulation and Rates for potential contingent matters associated with the Company’s regulated operations.

Future Regulatory Compliance Commitments

SPCC Rules.  In 2008 and 2009, the EPA adopted amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements.  On October 7, 2010, EPA amended the compliance date for certain facilities from November 10, 2010 to November 10, 2011.  The Company is currently reviewing the impact of the modified regulations on its operations in its Transportation and Storage and Gathering and Processing segments and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures.  Costs associated with such activities cannot be estimated with 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.

Air Quality Control

Transportation and Storage Segment. In August 2010, 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.  EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015.  In January 2010, 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.

26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In January 2010, 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, proposed revisions to the 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 Kansas Department of Health and Environment set certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area.  These measures must be revised to conform to the requirements of the EPA ozone standard discussed above.  As such, the 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 proposed plan, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 New Mexico will address the sulfur dioxide standard.

13.  Reportable Segments

The Company’s 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.  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.

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.

27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure.  The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:

·   items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;

·   income taxes;

·   interest;

·   dividends on preferred stock; and

·   loss on extinguishment of preferred stock.

EBIT 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.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.  There were no material intersegment revenues during the three- and six-month periods ended June 30, 2011 and 2010.

28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2011			2010		2011			2010
	(In thousands)
Operating revenues from external customers:
Transportation and Storage	$	189,760		$	187,090	$	392,054		$	373,765
Gathering and Processing		328,515			282,707		552,167			543,567
Distribution		109,076			99,711		425,649			407,972
Total segment operating revenues		627,351			569,508		1,369,870			1,325,304
Corporate and other activities		4,256			3,588		8,559			6,786
	$	631,607		$	573,096	$	1,378,429		$	1,332,090
Depreciation and amortization:
Transportation and Storage	$	31,963		$	30,896	$	64,237		$	60,073
Gathering and Processing		18,065			17,971		35,852			35,291
Distribution		8,407			7,967		16,814			15,923
Total segment depreciation and amortization		58,435			56,834		116,903			111,287
Corporate and other activities		860			725		1,719			1,466
	$	59,295		$	57,559	$	118,622		$	112,753
Earnings from unconsolidated investments:
Transportation and Storage	$	24,852		$	25,748	$	50,883		$	42,994
Gathering and Processing		(158	)		1,395		30			2,380
Corporate and other activities		354			399		836			746
	$	25,048		$	27,542	$	51,749		$	46,120
Segment performance:
Transportation and Storage EBIT	$	117,495		$	111,246	$	239,593		$	213,671
Gathering and Processing EBIT		21,333			40,526		9,104			47,081
Distribution EBIT		3,374			6,865		26,941			35,710
Total segment EBIT		142,202			158,637		275,638			296,462
Corporate and other activities		(1,908	)		297		(469	)		617
Interest expense		54,933			55,436		110,504			106,312
Federal and state income taxes		25,588			28,609		44,230			59,418
Net earnings		59,773			74,889		120,435			131,349
Preferred stock dividends		-			2,170		-			4,341
Loss on extinguishment of preferred stock		-			3,295		-			3,295
Net earnings available for common
stockholders	$	59,773		$	69,424	$	120,435		$	123,713

29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

		June 30,		December 31,
		2011		2010
		(In thousands)
Total assets:
Transportation and Storage		$	5,281,414	$	5,224,992
Gathering and Processing			1,740,188		1,700,598
Distribution			989,680		1,135,352
	Total segment assets		8,011,282		8,060,942
Corporate and other activities			178,787		177,601
Total assets		$	8,190,069	$	8,238,543
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(In thousands)
Expenditures for long-lived assets:
Transportation and Storage		$	28,911	$	25,886	$	39,169	$	56,257
Gathering and Processing			20,903		15,823		56,513		41,706
Distribution			13,447		9,151		20,409		16,255
	Total segment expenditures for long-lived
	assets		63,261		50,860		116,091		114,218
Corporate and other activities			1,321		4,166		1,904		6,281
	Total expenditures for long-lived assets (1)	$	64,582	$	55,026	$	117,995	$	120,499

_______________________

(1)   ­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­Related cash impact includes the net reduction in capital accruals totaling $10.4 million and $7.9 million for the three-month periods ended  June 30,  2011 and 2010, respectively.  ­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­­Related cash impact includes the net reduction in capital accruals totaling $26 million and $(7.9) million for the six-month periods ended June 30,  2011 and 2010, respectively.

14.  Regulation and Rates

Panhandle.  On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, with initial accumulated net costs of approximately $38 million included in the filing.  On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings with FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts.  The Administrative Law Judge issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted shippers, over a recovery period of 21.4 years and including applicable carrying charges.  The Company, as well as other parties, have filed briefs for exception on certain aspects of the decision.  On March 1, 2011, Sea Robin submitted its latest semiannual filing related to the surcharge, which reflected updated costs incurred through December 31, 2010 of approximately $54 million, net of insurance and surcharge recoveries, which were reflected in the updated surcharge rate effective April 1, 2011, subject to refund.  The ultimate outcome of this matter is still pending a final FERC decision.

30

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Missouri Gas Energy.  On July 13, 2011, a joint application was filed by Southern Union, Sigma and ETE requesting that the MPSC authorize Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union.  Although no procedural schedule has been established, on July 14, 2011, the MPSC issued an order directing its staff to file, by August 15, 2011, its recommendation regarding the proposed merger, or a status report indicating when it will be able to file its recommendation.  For additional related information, see Note 3 – ETE Merger.

On June 10, 2011, Missouri Gas Energy filed an application with the MPSC requesting authority to defer the financial impact of the tornado which struck Joplin, Missouri on May 22, 2011, on the grounds that the tornado constituted a material, extraordinary and non-recurring event with respect to Missouri Gas Energy’s operations.  If deferral authority is granted, Missouri Gas Energy would be permitted to defer as a regulatory asset for consideration of recovery in a future rate proceeding the incremental costs and lost fixed cost recovery occasioned by the tornado.  It is expected that the MPSC will address this request within a reasonable, but presently unknown time frame, but in no event later than January 2012.

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 percent of its total customers and approximately 91 percent 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.  Those judicial review proceedings are not expected to be complete until 2012, and the results of those judicial review proceedings are not expected to have a material adverse impact on the Company’s consolidated financial position, results of operations or cash flows.

New England Gas Company.  On September 16, 2010, New England Gas Company made a filing with the MDPU seeking to implement an annual base rate increase of approximately $6.2 million.  On March 31, 2011, the MDPU issued its order in this matter, awarding New England Gas Company a base rate increase of approximately $5.1 million and authorizing implementation of a revenue decoupling mechanism, which mitigates conservation and weather impacts, and implementation of a targeted infrastructure recovery factor, which permits recovery of revenue requirement (return, depreciation, property taxes and income taxes) associated with replacement of certain aged facilities without the necessity of filing and prosecuting a base rate increase.  The new rate structure and rates became effective for gas sold on and after April 1, 2011.

On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent.  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 percent 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

31

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

year 2007 and that such amount should be recovered over a 12-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 May 13, 2011, the independent auditor selected by the MDPU submitted the final audit report pertaining to 2007 cost of service information as ordered by the MDPU in connection with New England Gas Company’s 2008 base rate proceeding.  The Company does not expect further activity in the proceeding unless the MDPU orders further action in response to the final audit report submission.

15.  Stockholders’ Equity

Dividends.  The table below presents the amount of cash dividends declared and paid in the period.

Shareholder	Date	Amount		Amount
Record Date	Paid	Per Share		Paid
				(In thousands)
June 24, 2011	July 8, 2011	$	0.15		$	18,709
March 25, 2011	April 8, 2011		0.15			18,700

32

ITEM 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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 financial condition, changes in financial condition and 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 on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources and other matters.

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and NGL in a safe, efficient and dependable manner.  The Company’s reportable business segments are determined 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.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance in its Transportation and Storage, Gathering and Processing, and Distribution segments using several factors, of which the primary financial measure is EBIT, a non-GAAP measure.  For additional information related to the Company’s use of EBIT as its primary financial measure for its reportable segments, see Part I, Item I. Financial Statements (Unaudited), Note 13 – Reportable Segments.

The following table provides a reconciliation of EBIT (by segment) to Net earnings available for common stockholders for the periods presented.

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
	(In thousands)
EBIT:
Transportation and storage segment	$	117,495		$	111,246	$	239,593		$	213,671
Gathering and processing segment		21,333			40,526		9,104			47,081
Distribution segment		3,374			6,865		26,941			35,710
Corporate and other activities		(1,908	)		297		(469	)		617
Total EBIT		140,294			158,934		275,169			297,079
Interest expense		54,933			55,436		110,504			106,312
Earnings before income taxes		85,361			103,498		164,665			190,767
Federal and state income tax expense		25,588			28,609		44,230			59,418
Net earnings		59,773			74,889		120,435			131,349
Preferred stock dividends		-			2,170		-			4,341
Loss on extinguishment of preferred stock		-			3,295		-			3,295
Net earnings available for common stockholders	$	59,773		$	69,424	$	120,435		$	123,713

33

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010.  The Company’s $9.7 million decrease in Net earnings available for common stockholders was primarily due to:

·   Lower EBIT contribution of $19.2 million from the Gathering and Processing segment largely attributable to lower gross margin of $14.7 million resulting from the impact of a $2.5 million net hedging loss in 2011 versus a net hedging gain of $26.8 million in 2010, offset by a higher net revenue margin of $14.6 million (unadjusted for the impact of hedges) primarily due to higher market-driven realized average natural gas and NGL prices in the 2011 period;

·   Lower EBIT contribution of $3.5 million from the Distribution segment mainly due to higher operating, maintenance and general expenses of $4.8 million primarily due to the impact of a $1.5 million favorable environmental settlement realized in 2010 and higher provisions for uncollectible accounts of $1.1 million in 2011, partially offset by higher net operating revenues of $700,000 largely attributable to the impact of new customer rates effective April 1, 2011 at New England Gas Company; and

·   Lower EBIT contribution of $2.2 million from Corporate and other activities primarily due to legal and other outside service costs related to the potential merger with ETE.

These reductions in earnings were partially offset by:

·   Higher EBIT contribution of $6.2 million from the Transportation and Storage segment as Panhandle’s contribution increased $7.1 million on lower operating, maintenance and general expense of $4.9 million primarily attributable to reduced legal expenses resulting from a litigation settlement in the second quarter of 2011 and higher operating revenue of $2.7 million mainly due to higher short term capacity sold on Trunkline and PEPL;

·   Lower preferred stock dividends of $5.5 million due to the Company’s redemption of all of its outstanding shares of preferred stock in July 2010; and

·   Lower federal and state income tax expense of $3 million primarily due to lower pre-tax earnings in 2011.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010.  The Company’s $3.3 million decrease in Net earnings available for common stockholders was primarily due to:

·   Lower EBIT contribution of $38 million from the Gathering and Processing segment largely attributable to lower gross margin of $28.7 million resulting from the impact of a $14.5 million net hedging loss in 2011 versus a net hedging gain of $20.9 million in 2010 and higher operating expenses of $5.7 million, offset by a higher net revenue margin of $6.7 million (unadjusted for the impact of hedges) driven by higher market-driven realized average NGL prices in the 2011 period;

·   Lower EBIT contribution of $8.8 million from the Distribution segment mainly due to higher operating, maintenance and general expenses of $7.8 million largely attributable to higher legal, injuries and damages costs of $3 million and the impact of a $1.5 million favorable environmental settlement realized in 2010; and

· Higher interest expense of $4.2 million primarily attributable to the impact of the lower level of interest costs capitalized attributable to lower average capital project balances outstanding in 2011.

These reductions in earnings were partially offset by:

·   Higher EBIT contribution of $25.9 million from the Transportation and Storage segment as Panhandle’s contribution increased $18 million on higher operating revenue of $18.3 million mainly due to the LNG terminal infrastructure enhancement project being placed in service in March 2010 and higher equity earnings of $7.9 million from the Company’s unconsolidated investment in Citrus largely driven by higher transportation revenues resulting from placing Florida Gas’ Phase VIII Expansion project into service on April 1, 2011;

34

·   Lower federal and state income tax expense of $15.2 million primarily due to lower pre-tax earnings in 2011, the impact of $5.3 million of state investment tax credits recorded in 2011 and $4.2 million of higher income tax expense in 2010 resulting from the elimination of the Medicare Part D tax subsidy in the Patient Protection and Affordable Care Act (PPACA) legislation signed into law in March 2010; and

·   Lower preferred stock dividends of $7.6 million due to the Company’s redemption of all of its outstanding shares of preferred stock in July 2010.

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 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 EBIT 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.

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.

35

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,
	2011		2010		2011		2010
	(In thousands, except volumes)
Operating revenues (1)	$	189,760	$	187,090	$	392,054	$	373,765
Operating, maintenance and general		56,914		61,828		121,559		124,906
Depreciation and amortization		31,963		30,896		64,237		60,073
Taxes other than on income and revenues		8,436		8,897		17,741		18,125
Total operating income		92,447		85,469		188,517		170,661
Earnings from unconsolidated investments		24,852		25,748		50,883		42,994
Other income, net		196		29		193		16
EBIT	$	117,495	$	111,246	$	239,593	$	213,671
Panhandle natural gas volumes transported (TBtu): (2)
PEPL		128		123		299		290
Trunkline		182		167		377		321
Sea Robin		34		43		68		90
Florida Gas natural gas volumes transported (3)		235		214		416		403

_____________

(1)   Reservation revenues comprised 90 percent, 88 percent, 90 percent and 89 percent of total operating revenues in the three months ended June 30, 2011 and 2010 and the six months ended June 30, 2011 and 2010, respectively.

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

(3)   Represents 100 percent of Florida Gas natural gas volumes transported versus the Company’s effective equity ownership interest of 50 percent.

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010. The $6.2 million EBIT improvement in the period ended June 30, 2011 versus the same period in 2010 was primarily due to a higher EBIT contribution from Panhandle totaling $7.1 million, partially offset by lower equity earnings of $900,000, mainly from the Company’s unconsolidated investment in Citrus.

Panhandle’s $7.1 million EBIT improvement was mainly due to:

·   Lower operating, maintenance and general expenses of $4.9 million in 2011 versus 2010 primarily attributable to:

o   A $12.7 million decrease in legal expenses primarily due to settlement of certain litigation in the second quarter of 2011 with several contractors related to the Company’s East End project;

o   Impact of a net reduction of $3.5 million in the 2010 period in the repair and abandonment cost provision for Hurricanes Ike and Gustav resulting from favorable weather conditions experienced and increased project efficiencies and Hurricane Ike insurance recoveries of $700,000 received in 2010;

o   A $1 million increase in fuel tracker costs primarily due to an under-recovery in 2011;

o   Higher allocated corporate service costs of $900,000 primarily due to higher employee benefits;

o   An $800,000 increase in medical costs; and

o   A $700,000 increase in compensation expense largely due to mark-to-market adjustments for liability share-based compensation awards (which are settled in cash) resulting from an increase in the Southern Union stock price impacted by the potential merger with ETE;

36

·   Higher operating revenues of $2.7 million primarily due to:

o   Higher short-term capacity sold of $2.5 million on Trunkline and PEPL based on operational availability;

o   Higher LNG revenues of $900,000 primarily due to a higher rate effective March 2011, partially offset by lower volumes from decreased LNG cargoes during 2011; and

o   Lower interruptible parking revenues of $1 million due to less favorable market conditions; and

·   Increased depreciation and amortization expense of $1.1 million in 2011 versus 2010 primarily due to a $103.6 million increase in property, plant and equipment placed in service after June 30, 2010.  Depreciation and amortization expense is expected to continue to increase primarily due to ongoing capital additions.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were lower by $900,000 in 2011 versus 2010 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share in Citrus:

·   Lower other income of $13.1 million largely driven by lower equity AFUDC due to placing Florida Gas’ Phase VIII Expansion project into service on April 1, 2011;

·   Higher interest expense of $7.9 million primarily due to lower capitalized debt AFUDC, mainly due to placing the Phase VIII Expansion project into service and higher interest on the $500 million 5.45% Senior Notes and $350 million 4.00% Senior Notes issued in July 2010, partially offset by lower interest on the $325 million 7.625% Senior Notes due December 2010 redeemed in August 2010;

·   Higher depreciation expense of $4 million primarily due to completion of the Phase VIII Expansion project;

·   A $2.2 million increase in operating expenses in the 2011 period mainly due to the Phase VIII Expansion project being place into service and other operating cost increases for materials and outside services; and

·   Higher transportation revenues of $27 million primarily due to placing the Phase VIII Expansion project into service on April 1, 2011.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010. The $25.9 million EBIT improvement in the period ended June 30, 2011 versus the same period in 2010 was primarily due to a higher EBIT contribution from Panhandle totaling $18 million and higher equity earnings of $7.9 million, mainly from the Company’s unconsolidated investment in Citrus.

Panhandle’s $18 million EBIT improvement was mainly due to:

·   Higher operating revenues of $18.3 million primarily due to:

o   Higher LNG revenues of $17.5 million primarily due to the LNG terminal infrastructure enhancement construction project placed in service in March 2010;

o   Higher transportation reservation revenues of $3.1 million primarily due to higher short-term capacity sold on Trunkline based on operational availability;

o   Lower transportation interruptible revenues of $1.6 million largely attributable to lower volumes in 2011 on Sea Robin primarily resulting from market conditions; and

o   Lower interruptible parking revenues of $1.4 million due to less favorable market conditions;

·   Lower operating, maintenance and general expenses of $3.3 million in 2011 versus 2010 primarily attributable to:

o   A $9.4 million net reduction in legal expenses resulting from the settlement of certain litigation in the second quarter of 2011 with several contractors related to the Company’s East End project;

o   Impact of a net reduction of $3.5 million in the 2010 period in the repair and abandonment cost provision for Hurricanes Ike and Gustav resulting from favorable weather conditions experienced and increased project efficiencies; and

o   A $3.4 million increase in fuel tracker costs primarily due to a net under-recovery in 2011 versus an over-recovery in 2010; and

37

·   Increased depreciation and amortization expense of $4.2 million in 2011 versus 2010 primarily due to the LNG terminal infrastructure enhancement construction project placed in service in March 2010 and a $103.6 million increase in property, plant and equipment placed in service after June 30, 2010.  Depreciation and amortization expense is expected to continue to increase primarily due to ongoing capital additions.

Equity earnings, mainly attributable to the Company’s unconsolidated investment in Citrus, were higher by $7.9 million in 2011 versus 2010 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share in Citrus:

·   Higher transportation revenues of $26.9 million primarily due to placing the Phase VIII Expansion project into service on April 1, 2011;

·   Higher interest expense of $7.2 million primarily due to higher interest on the $500 million 5.45% Senior Notes and $350 million 4.00% Senior Notes issued in July 2010 and lower capitalized debt AFUDC mainly due to placing the Phase VIII Expansion project into service, partially offset by lower interest on the $325 million 7.625% Senior Notes due December 2010 redeemed in August 2010;

·   Higher operating expenses of $4.3 million primarily for pipeline integrity assessments;

·   Higher depreciation expense of $3 million primarily due to completion of the Phase VIII Expansion project, partially offset by reduced depreciation rates associated with the rate case settlement approved by FERC on February 24, 2011; and

·   Higher income tax expense of $6.4 million primarily due to higher pre-tax earnings.

Equity earnings from the Citrus investment for the remainder of 2011 are anticipated to be lower, as the peak AFUDC (non-cash income) related to the Phase VIII Expansion project recognized in the first quarter of 2011 ceased effective with the April 1, 2011 in-service date and will likely only be partially offset by anticipated higher revenues, net of operating expenses and depreciation, since the incremental capacity from the project is not yet fully subscribed.

See Part I, Item 1. Financial Statements (Unaudited), Note 3 – ETE Merger and Note 5 – Unconsolidated Investments – Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus for additional information related to Citrus and Florida Gas.

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.

38

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 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment and Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk – Gathering and Processing Segment.

39

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,
	2011			2010			2011			2010
	(In thousands, except volumes and
	average pricing)
Operating revenues, excluding impact of
commodity derivative instruments	$	330,992		$	255,917		$	566,632		$	522,627
Realized and unrealized commodity derivatives		(2,477	)		26,790			(14,465	)		20,940
Operating revenues		328,515			282,707			552,167			543,567
Cost of natural gas and other energy (1)		(266,306	)		(205,792	)		(459,500	)		(422,249	)
Gross margin  (2)		62,209			76,915			92,667			121,318
Operating, maintenance and general		21,191			18,489			44,105			38,363
Depreciation and amortization		18,065			17,971			35,852			35,291
Taxes other than on income and revenues		1,466			1,331			3,726			2,965
Total operating income		21,487			39,124			8,984			44,699
Earnings (loss) from unconsolidated investments		(158	)		1,395			30			2,380
Other income, net		4			7			90			2
EBIT	$	21,333		$	40,526		$	9,104		$	47,081
Operating Information:
Volumes
Avg natural gas processed (MMBtu/d)		431,453			436,178			402,978			425,052
Avg NGL produced (gallons/d)		1,557,025			1,483,284			1,414,597			1,426,420
Avg natural gas wellhead volumes (MMBtu/d)		505,238			545,105			478,618			536,927
Natural gas sales (MMBtu)  (3)		18,031,648			20,572,042			34,635,292			40,381,059
NGL sales (gallons) (3)		186,343,102			163,849,470			322,661,727			306,449,086
Average Pricing
Realized natural gas ($/MMBtu)  (4)	$	4.19		$	4.07		$	4.12		$	4.58
Realized NGL ($/gallon)  (4)		1.35			1.04			1.29			1.08
Natural Gas Daily WAHA ($/MMBtu)		4.24			4.13			4.18			4.59
Natural Gas Daily El Paso ($/MMBtu)		4.17			4.04			4.13			4.52
Estimated plant processing spread ($/gallon)		0.97			0.61			0.91			0.64

________________

 (1)   Cost of naturalgas 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 measure is more 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)   Volumes processed by SUGS include volumes sold under various buy-sell arrangements.  For the three-month period ended June 30, 2010, the Company’s operating revenues and related volumes  attributable to its buy-sell arrangements for natural gas totaled $11.3 million and 2.4 million MMBtu.  For the six-month period ended June 30, 2010, the Company’s operating revenues and related volumes  attributable to its buy-sell arrangements for natural gas totaled $24.6 million and 4.7 million MMBtu.  The buy-sell arrangements for natural gas terminated in November 2010.  The Company’s operating revenues and related volumes attributable to its buy-sell arrangements for NGL totaled $37.1 million and $30.8 million and 28.3 million gallons and 32.4 million gallons, for the three-month periods ended June 30, 2011 and June 30, 2010, respectively.  The Company’s operating revenues and related volumes attributable to its buy-sell arrangements for NGL totaled $68.4 million and $57 million and 55.7 million gallons and 58.4 million gallons, for the six-month periods ended June 30, 2011 and June 30, 2010, respectively.

(4)   Excludes impact of realized and unrealized commodity derivative gains and losses detailed in the above EBIT presentation.

40

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010. The $19.2 million EBIT reduction in the period ended June 30, 2011 versus the same period in 2010 was primarily due to the following items:

·   Lower gross margin of $14.7 million primarily as the result of:

o   Impact of a net hedging loss of $2.5 million in the 2011 period versus a net hedging gain of $26.8 million in the 2010 period (which includes the impact of $300,000 of unrealized gains recorded in 2011);

o   Higher operating revenues of $75.1 million, excluding hedging gains and losses, largely attributable to higher market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $4.19 per MMBtu and $1.35 per gallon in the 2011 period versus $4.07 per MMBtu and $1.04 per gallon in the 2010 period, respectively; and

o   A $60.5 million increase in the cost of gas and other energy in the 2011 period versus the 2010 period due to higher market-driven natural gas and NGL purchase costs; and

·   Higher operating, maintenance and general expenses of $2.7 million primarily due to:

o   Higher labor costs of $600,000 primarily due to an increased overall headcount in the 2011 period;

o   Higher compensation expense of $500,000 largely due to mark-to-market adjustments for liability share-based compensation awards (which are settled in cash) resulting from an increase in the Southern Union stock price impacted by the potential merger with ETE;

o   An increase in chemicals and lubricants costs of $500,000, which generally track with the price of oil; and

o   Higher contract services of $500,000 primarily associated with the plant down time experienced in early 2011 due to severe cold weather.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010. The $38 million EBIT reduction in the period ended June 30, 2011 versus the same period in 2010 was primarily due to the following items:

·   Lower gross margin of $28.7 million primarily as the result of:

o   Impact of a net hedging loss of $14.5 million in the 2011 period versus a net hedging gain of $20.9 million in the 2010 period (which includes the impact of $14.4 million of unrealized losses recorded in 2011);

o   Higher operating revenues of $44 million, excluding hedging gains and losses, largely attributable to higher market-driven realized average NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $1.29 per gallon in the 2011 period versus $1.08 per gallon in the 2010 period.  This increase was partially offset by lower realized average natural gas prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $4.12 per MMBtu in the 2011 period versus $4.58 per MMBtu in the 2010 period and reduced throughput volumes as a result of processing plant outages and producer well freeze-offs resulting from unusually cold weather in early 2011; and

o   A $37.3 million increase in the cost of gas and other energy in the 2011  period versus the 2010 period mainly due to higher market-driven NGL purchase costs, partially offset by lower natural gas costs in 2011; and

·   Higher operating, maintenance and general expenses of $5.7 million primarily due to:

o   Higher contract services of $1.8 million primarily associated with the plant down time experienced in early 2011 due to severe cold weather;

o   Increased costs of $1.5 million associated with the fire at the Keystone natural gas processing plant in January 2011;

o   An increase in chemicals and lubricants costs of $1.3 million, which generally track with the price of oil; and

o   Higher labor cost of $1 million primarily due to an increased overall headcount in the 2011 period.

41

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 EBIT occurring in the traditional winter heating season during the first and fourth calendar quarters.  On February 10, 2010, the MPSC issued an order approving continued use of a distribution rate structure that eliminates the impact of weather and conservation for Missouri Gas Energy’s residential margin revenues and related earnings and approving expanded use of that distribution rate structure for Missouri Gas Energy’s small general service customers, effective February 28, 2010.  Together, Missouri Gas Energy’s residential and small general service customers comprised 99 percent of its total customers and approximately 91 percent of its net operating revenues as of February 28, 2010.  For additional information related to rate matters within the Distribution segment, see Part I, Item 1. Financial Statements (Unaudited), Note 14 – 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,
	2011			2010			2011			2010
	($ in thousands)
Net operating revenues  (1)	$	55,633		$	54,955		$	123,472		$	124,239
Operating, maintenance and general		41,373			36,558			73,715			65,877
Depreciation and amortization		8,407			7,967			16,814			15,923
Taxes other than on income
and revenues		2,458			3,271			5,926			6,512
Total operating income		3,395			7,159			27,017			35,927
Other income (expenses), net		(21	)		(294	)		(76	)		(217	)
EBIT	$	3,374		$	6,865		$	26,941		$	35,710
Operating Information:
Natural gas sales volumes (MMcf)		6,401			7,285			39,820			40,842
Natural gas transported volumes (MMcf)		4,860			5,613			14,777			14,756
Weather – Degree Days: (2)
Missouri Gas Energy service territories		445			287			3,401			3,174
New England Gas Company service territories		664			777			3,585			3,375

___________________________

 (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.

42

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010.  The $3.5 million EBIT reduction in the period ended June 30, 2011 versus the same period in 2010 was primarily due to:

·   Higher operating, maintenance and general expenses of $4.8 million primarily attributable to:

o   Impact of a $1.5 million settlement in 2010 for a previous environmental cost reimbursement claim made by the Company;

o   Higher provisions for uncollectible customer accounts of approximately $1.1 million mainly resulting from the impact of decreased governmental assistance provided to Missouri Gas Energy’s low income customers;

o   Higher costs of approximately $1 million related to the tornadoes in Joplin, Missouri during the second quarter of 2011;

o   Higher legal, injuries and damage claims of $500,000 primarily due to ongoing litigation; and

o   Higher labor costs of $400,000 largely due to new positions filled in the 2011 period; and

·   Higher net operating revenues of $700,000 largely attributable to higher revenues at New England Gas Company primarily resulting from the impact of new customer rates effective April 1, 2011.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010. The $8.8 million EBIT reduction in the period ended June 30, 2011 versus the same period in 2010 was primarily due to:

·   Higher operating, maintenance and general expenses of $7.8 million primarily attributable to:

o   Higher legal, injuries and damage claims of $3 million primarily due to ongoing litigation;

o   Impact of a $1.5 million settlement in 2010 for a previous environmental cost reimbursement claim made by the Company;

o   Higher costs of approximately $1 million related to the tornadoes in Joplin, Missouri during the second quarter of 2011;

o   Higher amortized pension costs of $700,000, which were previously being deferred until such costs were included in Missouri Gas Energy’s new rates, which became effective February 28, 2010; and

o   Higher labor costs of $700,000 largely due to new positions filled in the 2011 period; and

·   Lower net operating revenues of $800,000 largely attributable to $3 million of lower net operating revenues at Missouri Gas Energy primarily due to the impact of the new customer rates effective February 28, 2010, which eliminated the impact of weather and conservation for the majority of Missouri Gas Energy’s revenues (resulting in lower reported revenues in the traditional winter heating season), partially offset by higher revenues of $2.3 million at New England Gas Company primarily due to colder weather in the 2011 winter season and the impact of new customer rates effective April 1, 2011.

Annual operating revenues are expected to be reduced by up to approximately $1 million as a result of the loss of approximately 3,000 customers in Joplin, Missouri from damage caused by the tornadoes during the second quarter of 2011.  For information related to the potential recovery in rates of incremental costs and the lost fixed cost recovery mechanism resulting from the tornadoes, see Item 1.  Financial Statements (Unaudited), Note 14 – Regulation and Rates – Missouri Gas Energy.

The Company has benefitted from various federal and state governmental programs that have provided home energy assistance to low income customers.  During 2011, the Company received, through grants made on behalf of customers, funding from these agencies totaling $5 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.

43

Corporate and Other Activites.

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010. The EBIT reduction of $2.2 million was primarily due to legal and other outside service costs of $3.1 million attributable to the potential merger with ETE.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010.  The EBIT reduction of $1.1 million was primarily due to legal and other outside service costs of $3.1 million attributable to the potential merger with ETE.

See Item 1.  Financial Statements (Unaudited), Note 3 – ETE Merger for additional information related to the Company’s potential merger with ETE.  On a consolidated basis, the Company recorded merger-related expenses of $4.7 million during the second quarter of 2011.

Interest Expense

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010.  Interest expense was $4.2 million higher in the period ended June 30, 2011 versus the same period in 2010 primarily due to the impact of $5.3 million of lower interest costs capitalized attributable to lower average capital project balances outstanding in 2011 compared to 2010 largely resulting from the LNG infrastructure enhancement project being placed in service in March 2010, partially offset by lower interest expense of $1.6 million resulting from the repayment of the $40.5 million 8.25% Senior Notes in April 2010 and the $100 million 6.089% Senior Notes in February 2010.  There were no significant changes in the average interest rates and average debt balances outstanding associated with the Company’s debt obligations in 2011 versus 2010.

Federal and State Income Taxes from Continuing Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010				2011			2010
	(In thousands)
Income tax expense	$	25,588		$	28,609			$	44,230		$	59,418
Effective tax rate (1)		30	%		28	%			27	%		31	%

________________

(1)   The EITR is generally lower than the U.S. federal income tax statutory rate of 35 percent primarily due to the 80 percent dividends received deduction for the anticipated receipt of dividends associated with earnings from the Company’s unconsolidated Citrus affiliate, partially offset by the impact of state income taxes, net of the federal income tax benefit.

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010. The $3 million decrease in federal and state income tax expense was primarily due to lower pre-tax earnings for the period ended June 30, 2011 versus the same period in 2010 and $2.2 million of higher state income tax expense (net of the federal tax benefit) mainly due to a statutory rate reduction recorded in 2010.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010. The $15.2 million decrease in federal and state income tax expense was primarily due to lower pre-tax earnings for the period ended June 30, 2011 versus the same period in 2010, the impact of $5.3 million of state investment tax credits recorded in 2011 and $4.2 million of higher income tax expense in 2010 resulting from the elimination of the Medicare Part D tax subsidy in the PPACA legislation signed into law in March 2010.

44

Preferred Stock Dividends

Three-month period ended June 30, 2011 versus the three-month period ended June 30, 2010.  The $5.5 million reduction in Preferred stock dividends for the period ended June 30, 2011 versus the same period in 2010 was due to the Company’s redemption of its remaining 4,600,013 depository shares outstanding representing 460,000 shares of its 7.55% Noncumulative Preferred Stock, Series A (Liquidation Preference $250 per share) (Preferred Stock) in July 2010.

Six-month period ended June 30, 2011 versus the six-month period ended June 30, 2010.  The $7.6 million reduction in Preferred stock dividends for the period ended June 30, 2011 versus the same period in 2010 was due to the Company’s redemption of its remaining 4,600,013 depository shares outstanding representing 460,000 shares of its Preferred Stock in July 2010.

LIQUIDITY AND CAPITAL RESOURCES

The Liquidity and Capital Resources information contained herein should be read in conjunction with the related information set forth in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of the Company’s Form 10-K for the year ended December 31, 2010.

Cash generated from internal operations constitutes the Company’s primary source of liquidity.  The Company’s working capital deficit at June 30, 2011 is $1.01 billion, including $816.3 million of the current portion of long-term debt.  Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings, capital markets and bank debt financings, and proceeds from asset dispositions.  The availability and terms relating to such liquidity will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure and conditions in the financial markets at the time of such offerings.

Sources (Uses) of Cash

	Six Months Ended June 30,
	2011				2010
	(In thousands)
Cash flows provided by (used in):
Operating activities		$	350,911			$	242,492
Investing activities			(216,390	)			(129,020	)
Financing activities			(134,807	)			(121,429	)
Increase (decrease) in cash and cash equivalents		$	(286	)		$	(7,957	)

45

Operating Activities

Cash provided by operating activities increased by $108.4 million in the 2011 period versus the same period in 2010.  Cash flows provided by operating activities before changes in operating assets and liabilities for the 2011 period were $269.5 million compared with $259.2 million for the 2010 period.  Changes in operating assets and liabilities provided cash of $81.4 million in the 2011 period and used cash of $16.7 million in the 2010 period, resulting in an increase in cash from changes in operating assets and liabilities of $98 million in 2011 compared to 2010.  The $98 million increase is primarily due to:

·   An increase in cash of $62.6 million in the Distribution segment associated with recovery of a higher amount of previously deferred natural gas purchase costs from customers in the 2011 period; and

·   An increase of cash of $13.1 million at Missouri Gas Energy primarily due to the impact of a one-time catch-up contribution to Missouri Gas Energy’s other postretirement benefit plan in the 2010 period in accordance with its approved rate case effective February 28, 2010.

Investing Activities

The Company’s current business strategy includes making prudent capital expenditures across its base of transmission, storage, gathering, processing and distribution assets and growing the businesses through the selective acquisition of assets in order to position itself favorably in the evolving natural gas markets.

Cash flows used in investing activities in the periods ended June 30, 2011 and June 30, 2010 were $216.4 million and $129 million, respectively.  The $87.4 million increase in investing cash outflows was primarily due to a $72 million loan the Company made to Citrus in the 2011 period to fund a portion of the Phase VIII Expansion costs and a $14.5 million increase in capital expenditures in the 2011 period.

See Part I, Item 1.  Financial Statements (Unaudited), Note 13 – Reportable Segments for information regarding the amount of capital expenditures made by each of the Company’s reportable segments.

Potential Sea Robin Impairment.  Sea Robin, comprised primarily of offshore facilities, suffered damage from Hurricane Ike related to several platforms and gathering pipelines.  As there were no new indicators of potential impairment during 2011, the impairment test on Sea Robin was not performed as of June 30, 2011.   Approximately $115 million of the approximately $150 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin and are substantially completed.  As of June 30, 2011, the Company has received approximately $51 million for claims submitted with respect to Hurricane Ike-related damage to Sea Robin.  The Company estimates approximately $10 million of additional insurance proceeds will ultimately be received for the claims related to Sea Robin.

Additionally, Sea Robin has implemented a rate surcharge initially approved by FERC in September 2009, subject to refund and final FERC decision, to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties.   To the extent the Company’s capital expenditures are not recovered from insurance proceeds or through its hurricane rate surcharge, its net investment in Sea Robin’s property, plant and equipment would have increased without necessarily generating additional revenues unless the incremental costs are recovered through future rate proceedings or additional throughput.  See Item 1. Financial Statements (Unaudited), Note 14 – Regulation and Rates for information related to the surcharge filing.  If Sea Robin’s hurricane surcharge is not ultimately approved for recovery from all shippers or Sea Robin experiences other adverse developments impacting anticipated future cash flows that are not remedied through rate proceedings, the Company could potentially be required to record an impairment of its net investment in Sea Robin.

46

Citrus Sponsor Contributions. In 2011, the Company, through an indirect wholly-owned subsidiary, and Citrus’ other shareholder each made sponsor contributions of $72 million in the form of loans to Citrus.   The Company has recorded the Citrus loan in Other non-current assets on the Condensed Consolidated Balance Sheet.  The contributions are related to the costs of Florida Gas' Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each shareholder 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 percent.  Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs. 

Financing Activities

The Company has historically demonstrated a commitment to strengthen its financial condition and solidify its current investment grade status, as evidenced by the issuance of common stock, equity units, preferred stock and asset sales and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with past acquisitions.

Financing activities used cash flows of $134.8 million and $121.4 million in the periods ended June 30, 2011 and June 30, 2010, respectively.  The $13.4 million increase in net financing cash outflows was primarily due to:

·   Repayments of $101.6 million under the Company’s credit facilities in the 2011 period compared to $76.1 million of borrowings in 2010; and

·   Net repayments of $139.9 million of long-term debt in the 2010 period.

Retirement of Debt Obligations.  The Company expects to refinance and/or extend the $455 million term loan due March 2012 and the $465 million term loan due June 2012.  The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance these obligations under acceptable terms prior to their maturity. 

Credit Facilities.  During the second quarter of 2011, the Company entered into the 2011 Revolver in the amount of $550 million.  The 2011 Revolver is an amendment, restatement and refinancing of the Company’s existing $550 million Revolver, which was otherwise scheduled to mature on May 28, 2013.  The 2011 Revolver will mature on May 20, 2016.  Borrowings on the 2011 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 2011 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 2011 Revolver at June 30, 2011 were LIBOR, plus 162.5 basis points, and 25 basis points, respectively.  

Floating-Rate Debt Obligations.  The Company has $570 million available under its committed credit facilities.  As of August 5, 2011, there was a balance of $227.9 million outstanding under the Company’s credit facilities, with an effective interest rate of 1.78 percent.

As of August 5, 2011, the interest rate on the $465 million term loan was 0.74 percent.

47

Credit Ratings. As of June 30, 2011, both Southern Union’s and Panhandle’s debt was rated BBB- by Fitch Ratings, Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. Due to the merger activities involving the Company, Standard and Poor’s has placed Southern Union and Panhandle on Credit Watch with developing implications, Moody’s has revised its outlook on Southern Union’s debt from stable to negative, and Fitch has placed Southern Union and Panhandle on Rating Watch Negative.  The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of the Company’s lending agreements.  However, if its current credit ratings are downgraded below investment grade or if there are times when it is placed on "credit watch," the Company could be negatively impacted as follows:

·   Borrowing costs associated with existing debt obligations could increase annually up to approximately $6.6 million in the event of a credit rating downgrade;

·   The costs of refinancing debt that is maturing or any new debt issuances could increase due to being placed on credit watch or due to a credit rating downgrade;

·   The costs of maintaining certain contractual relationships could increase, primarily related to the potential requirement for the Company to post collateral associated with its derivative financial instruments; and

·   Regulators may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

For additional related information, see Part I, Item 1.  Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Derivative Instrument Contingent Features.

OTHER MATTERS

Contingencies

See Part I, Item 1.  Financial Statements (Unaudited), Note 12 – Commitments and Contingencies, in this Quarterly Report on Form 10-Q.

Inflation

The Company believes that inflation has caused, and may continue to cause, increases in certain operating expenses, and will continue to require higher capital replacement and construction costs.  In the Transportation and Storage and Distribution segments, the Company continually reviews the adequacy of its rates in relation to such increasing cost of providing services, the inherent regulatory lag experienced in adjusting its rates and the rates it is actually able to charge in its markets.

48

Regulatory

The following table summarizes the status of rate proceedings applicable to the Transportation and Storage segment.

	Date of Last
Company	Rate Filing	Rate Proceedings Status
PEPL	May 1992	Settlement effective April 1997
Trunkline	January 1996	Settlement effective May 2001
Sea Robin	June 2007	Settlement effective December 2008  (1)
Trunkline LNG	June 2001	Settlement effective January 2002   (2)
Southwest Gas Storage	August 2007	Settlement effective February 2008
Florida Gas	October 2009	Settlement effective April  2011 (3)

________________________

(1)Settlement requires another rate case to be filed by January 2014.

(2)Settlement provides for a rate moratorium through 2015.  Current fixed rates apply through 2015 covering all facilities, except the IEP expansion facilities placed in service in March 2010 which have negotiated rates through March 2030.

(3)    Settlement provides for a rate moratorium until January 1, 2013 and requires another rate case to be filed by November 2014.

See Part I, Item 1.  Financial Statements (Unaudited), Note 14 – Regulation and Rates in this Quarterly Report on Form 10-Q.

Trunkline LNG Cost and Revenue Study.On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study with respect to the Trunkline LNG facility expansions completed in 2006, in compliance with FERC orders.  Such filing, which was as of March 31, 2009, reflected an annualized cost of service level for these expansions of $54.7 million, less than the associated actual revenues during the same period of $68.5 million.  These expansion revenues are currently at negotiated rates totaling $72.6 million annually through 2015.  BG LNG Services (BGLS) filed a motion to intervene and protest on July 14, 2009.  By order dated July 26, 2010, FERC determined that since (i) Trunkline LNG has fixed negotiated rates with BGLS through 2015, which would be unaffected by any rate change that might be determined through hearing at this time, and (ii) current costs and revenues are not necessarily representative of Trunkline LNG’s costs and revenues at the termination of the negotiated rate period in 2015, there was no reason to expend FERC’s and the parties’ resources on a Natural Gas Act Section 5 proceeding at this time.  The order is final and not subject to rehearing.

LNG Export License.  On July 22, 2011, the United States Department of Energy, Office of Fossil Energy issued an order authorizing Lake Charles Exports, LLC, a jointly-owned subsidiary of the Company and BG Group plc, to export domestically produced LNG by vessel from Trunkline LNG’s Lake Charles LNG terminal.  The authorization, for a 25 year term beginning on the earlier of the date of first export or 10 years from the issuance of the order, permits export of up to approximately 2 Bcf/d to countries that have or will enter into a free trade agreement (FTA) with the United States that requires national treatment for trade in natural gas.  Lake Charles Exports, LLC is permitted to use the authorization to export LNG on its own behalf or as an agent for BG LNG Services.  A proceeding for approval to export to non-FTA countries is ongoing.  The companies are developing plans to install liquefaction facilities at the Lake Charles terminal to export LNG. Modifications to the Lake Charles terminal would be subject to approval by the FERC.  The Company and BG Group plc have not finalized the economic terms of their arrangement, but the Company expects that any such arrangement will take into account, among other things, the December 31, 2015 termination of certain contracted rates at the existing Trunkline LNG terminal which otherwise revert to tariff rates in 2016 and the term of BGLS contracts related to the Trunkline LNG terminal which otherwise all expire in 2030. 

49

ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk.

The information contained in Item 3 updates, and should be read in conjunction with, related information set forth in Part II, Item 7A in the Company's Annual Report on Form 10-K for the year ended December 31, 2010, in addition to the unaudited interim condensed consolidated financial statements, accompanying notes, and Management's Discussion and Analysis of Financial Condition and Results of Operations presented in Part I, Items 1 and 2 of this Quarterly Report on Form 10-Q.

Interest Rate Risk

The Company is subject to the risk of loss associated with movements in market interest rates.  The Company manages this risk through the use of fixed-rate debt, floating-rate debt and interest rate swaps.  Fixed-rate swaps are used to reduce the risk of increased interest costs during periods of rising interest rates.  Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates.  At June 30, 2011, the interest rate on 83 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At June 30, 2011, $23.4 million is included in Derivative instruments - liabilities and $11 million is included in Deferred Credits in the unaudited interim Condensed Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012 and a portion of the $600 million Junior Subordinated Notes due 2066.

At June 30, 2011, a 100 basis point change in the annual interest rate on all outstanding floating-rate debt would correspondingly change the Company’s interest payments by approximately $700,000 for each month during which such change continued.  If interest rates change significantly, the Company may take actions to manage its exposure to the change.

The Company enters into treasury rate locks from time to time to manage its exposure against changes in future interest payments attributable to changes in US treasury rates.  By entering into these agreements, the Company locks in an agreed upon interest rate until the settlement of the contract, which typically occurs when the associated long-term debt is sold.  The Company accounts for the treasury rate locks as cash flow hedges.  The Company’s most recent treasury rate locks were settled in February and June 2008.

The change in exposure to loss in earnings and cash flow related to interest rate risk for the quarter ended June 30, 2011 is not material to the Company.

See Part I, Item 1.  Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities and Note 7 - Debt Obligations.

Commodity Price Risk

Gathering and Processing Segment.  The Company markets natural gas and NGL in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments.  These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts, but also the risks associated with unmatched positions and market fluctuations.  The Company is required to record its commodity derivative financial instruments at fair value, which is affected by commodity exchange prices, over-the-counter quotes, volatility, time value, credit and counterparty credit risk and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.

50

To manage its commodity price risk related to natural gas and NGL, the Company may use a combination of (i) natural gas puts, price swaps and basis swaps, (ii) NGL price swaps, (iii) NGL processing spread puts and swaps, and (iv) other exchange-traded futures and options.  These derivative financial instruments allow the Company to preserve value and protect margins.

The Company realizes NGL, NGL processing spread and/or natural gas volumes from the contractual arrangements associated with the natural gas treating and processing services it provides.  Forecasted NGL, NGL processing spread and/or natural gas volumes compared to the actual volumes sold and the effectiveness of the associated economic hedges utilized by the Company can be unfavorably impacted by:

·    processing plant outages;

·    limitations on treating capacity;

·   higher than anticipated fuel, flare and unaccounted-for natural gas levels;

·   impact of commodity prices in general;

·   decline in drilling and/or connections of new supply;

·   limitations in available natural gas and NGL take-away capacity;

·   reduction in NGL available from wellhead supply;

·   lower than expected recovery of NGL from the inlet natural gas stream;

·   lower than expected receipt of natural gas volumes to be processed;

·   limitations on NGL fractionation capacity;

·   renegotiation of existing contracts;

·   change in contracting practices vis-à-vis type(s) of processing contracts;

·   competition for new wellhead supplies; and

·   changes to environmental or other laws and regulations.

51

The following table summarizes SUGS' principal commodity derivative instruments as of June 30, 2011 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes.

		Average		Volumes		Fair Value
		Fixed Price		(MMBtu/d)		of Assets
Instrument Type	Index	(per MMBtu)		2011	2012	(Liabilities)  (6)
						(In thousands)
Natural Gas - Cash Flow Hedges:  (1)(4)
Receive-fixed swap	Gas Daily - Waha/El Paso Permian	$	6.12	25,000	-	$	8,253
Receive-fixed swap	Gas Daily - Waha/El Paso Permian	$	4.46	20,000	-		514
Receive-fixed swap	Gas Daily - Waha/El Paso Permian	$	4.82	-	10,000		738
				45,000	10,000	$	9,505
Processing Spread - Economic Hedges:  (3)
Receive-fixed swap	Gas Daily - Waha/El Paso Permian & OPIS Mt. Belvieu	$	5.51	25,000	-	$	(26,716)
		Average		Volumes		Fair Value
		Fixed Price		(Gallons/d)		of Assets
Instrument Type	Index	(per Gallon)		2011	2012	(Liabilities)  (6)
						(In thousands)
Natural Gas Liquids - Cash Flow Hedges:  (2)
Receive-fixed swap  (5)	OPIS Mt. Belvieu	$	1.15	-	178,629	$	(3,244)

__________________

(1)   The Company’s natural gas swap arrangements have been designated as cash flow hedges.  The effective portion of changes in the fair value of the cash flow hedges is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.

(2)   The Company's NGL swap arrangements have been designated as cash flow hedges.  The effective portion of changes in the fair value of the cash flow hedges is recorded in Accumulated other comprehensive loss until the related hedged items impact earnings.  Any ineffective portion of a cash flow hedge is reported in current-period earnings.

(3)   The Company’s processing spread swap arrangements, which hedge the pricing differential between NGL volumes and natural gas volumes, are treated as economic hedges.  The ratio of NGL product sold per MMBtu is approximately:  34 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 15 percent natural gasoline.  The change in fair value is reported in current-period earnings.

(4)   Volumes are applicable to the period July 1, 2011 to December 31, 2011, with 55.25 percent of the volumes settled against Gas Daily - Waha and 44.75 percent of the volumes settled against Gas Daily - El Paso Permian.

(5)   The Company's NGL swap arrangements consist of a ratio of NGL product that is approximately (on a gallon basis): 44 percent ethane, 29 percent propane, 4 percent iso-butane, 11 percent normal butane and 12 percent natural gasoline.  The arrangements approximate 15,000 MMBtu/d equivalents at a weighted average fixed price of $13.66 per MMBtu.

(6)   See Part I, Item 1.  Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment for additional related information.

At June 30, 2011, excluding the effects of hedging and assuming normal operating conditions, the Company estimates that a change in price of $0.01 per gallon of NGL and $1.00 per MMBtu of natural gas would impact annual gross margin by approximately $1.4 million and $8.5 million, respectively.  Such commodity price risk estimates do not include any effect on demand for the Company’s services that may be caused by, or arise in conjunction with, price changes.  For example, a change in the gross processing spread may cause some ethane to be sold in the natural gas stream, impacting gathering and processing margins, natural gas deliveries and NGL volumes shipped.

52

Transportation and Storage Segment. The Company is exposed to some commodity price risk with respect to natural gas used in operations by its interstate pipelines.  Specifically, the pipelines receive natural gas from customers for use in generating compression to move the customers’ natural gas.  Additionally, the pipelines may have to settle system imbalances when customers’ actual receipts and deliveries do not match.  When the amount of natural gas utilized in operations by the pipelines differs from the amounts provided by customers, the pipelines may use natural gas from inventory or may have to buy or sell natural gas to cover these or other operational needs, resulting in commodity price risk exposure to the Company.  In addition, there is other indirect exposure to the extent commodity price changes affect customer demand for and utilization of transportation and storage services provided by the Company.  At June 30, 2011, there were no hedges in place with respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment Economic Hedging Activities.  The Company enters into financial instruments to mitigate price volatility of purchased natural gas passed through to customers in its Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the natural gas purchase adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings. The fair values of the contracts are recorded as an adjustment to a regulatory asset or liability in the Consolidated Balance Sheet.  As of June 30, 2011, the fair values of the contracts, which expire at various times through June 2013, are included in the unaudited interim Condensed Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of natural gas of $13.7 million.

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 CEO and CFO, 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 CEO and CFO, 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 CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2011.

Changes in Internal Controls

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This reportcontains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.  Forward-looking statements are based on management’s beliefs and assumptions.  These forward-looking statements, which address the Company’s expected business and financial performance, among other matters, are identified by terms and phrases such as:  anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast and similar expressions.  Forward-looking statements involve risks and uncertainties that may or could cause actual results to be materially different from the results predicted.  Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

53

·   changes in demand for natural gas or NGL and related services by customers, in the composition of the Company’s customer base and in the sources of natural gas or NGL accessible to the Company’s system;

·   the effects of inflation and the timing and extent of changes in the prices and overall demand for and availability of natural gas or NGL as well as electricity, oil, coal and other bulk materials and chemicals;

·   adverse weather conditions, such as warmer or colder than normal weather in the Company’s service territories, as applicable, and the operational impact of natural disasters;

·   changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and/or governmental bodies affecting or involving the Company, including deregulation initiatives and the impact of rate and tariff proceedings before FERC and various state regulatory commissions;

·   the speed and degree to which additional competition, including competition from alternative forms of energy, is introduced to the Company’s business and the resulting effect on revenues;

·   the impact and outcome of pending and future litigation and/or regulatory investigations, proceedings or inquiries;

·   the ability to comply with or to successfully challenge existing and/or or new environmental, safety and other laws and regulations;

·   unanticipated environmental liabilities;

·   the uncertainty of estimates, including accruals and costs of environmental remediation;

·   the impact of potential impairment charges;

·   exposure to highly competitive commodity businesses and the effectiveness of the Company's hedging program;

·   the ability to acquire new businesses and assets and to integrate those operations into its existing operations, as well as its ability to expand its existing businesses and facilities;

·   the timely receipt of required approvals by applicable governmental entities for the construction and operation of the pipelines and other projects;

·   the ability to complete expansion projects on time and on budget;

·   the ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies;

·   the impact of factors affecting operations such as maintenance or repairs, environmental incidents, natural gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;

·   the performance of contractual obligations by customers, service providers and contractors;

·   exposure to customer concentrations with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers;

·   changes in the ratings of the Company’s debt securities;

·   the risk of a prolonged slow-down in growth or decline in the United States economy or the risk of delay in growth or decline in the United States economy, including liquidity risks in United States credit markets;

·   the impact of unsold pipeline capacity being greater than expected;

·   changes in interest rates and other general market and economic conditions, and in the Company’s ability to continue to access its revolving credit facility and to obtain additional financing on acceptable terms, whether in the capital markets or otherwise;

·   declines in the market prices of equity and debt securities and resulting funding requirements for defined benefit pension plans and other postretirement benefit plans;

·   acts of nature, sabotage, terrorism or other similar acts that cause damage to the facilities or those of the Company’s  suppliers' or customers' facilities;

·   market risks beyond the Company’s control affecting its risk management activities including market liquidity, commodity price volatility and counterparty creditworthiness;

·   the availability/cost of insurance coverage and the ability to collect under existing insurance policies;

·   the risk that material weaknesses or significant deficiencies in internal controls over financial reporting could emerge or that minor problems could become significant;

·   changes in accounting rules, regulations and pronouncements that impact the measurement of the results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;

·   the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, environmental compliance, climate change initiatives, authorized rates of recovery of costs (including pipeline relocation costs), and permitting for new natural gas production accessible to the Company’s systems;

54

·   market risks affecting the Company’s pricing of its services provided and renewal of significant customer contracts;

·   other risks and unforeseen events, including other financial, operational and legal risks and uncertainties detailed from time to time in filings with the SEC;

·   actions taken to protect species under the Endangered Species Act and the effect of those actions on the Company’s operations; and

·   the likelihood and timing of the completion of the proposed merger with ETE, the terms and conditions of any required regulatory approvals of the proposed merger, the impact of the proposed merger on Southern Union’s employees and potential diversion of management’s time and attention from ongoing business during this time period.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Company’s forward-looking statements.  Other factors could also have material adverse effects on the Company’s future results.  These and other risks are described in greater detail in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 and its other reports filed with the SEC.  In light of these risks, uncertainties and assumptions, the events described in forward-looking statements might not occur or might occur to a different extent or at a different time than the Company has described.  The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law.

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 12 – 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, 2010.

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 12 – 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, 2010.

ITEM 1A.  Risk Factors.

Except for the additional risk factor information described below, 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 25, 2011.  The following additional risk factor information should be read in conjunction with the related disclosure in Part I. Item 1A.  Risk Factors, in Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2010.

55

Risks Related to the Merger

Southern Union’s ability to complete the merger is subject to the approval of its stockholders, the satisfaction of certain closing conditions and the receipt of consents from governmental entities which may impose restrictions or conditions that could adversely affect Southern Union and/or ETE.  Any of the foregoing could cause the merger to be delayed or abandoned.

The merger is subject to certain closing conditions, including the approval of the merger by Southern Union’s stockholders, the absence of injunctions or other legal restrictions and that no material adverse effect shall have occurred on either company. In addition, in order to complete the merger, approvals from various governmental entities must be obtained. These governmental entities, such as the MPSC, the FERC and, if necessary, the MDPU, may impose certain restrictions or obligations as conditions for their approval.  Such restrictions or conditions may be imposed on the business and operations of Southern Union and/or ETE in connection with the completion of the merger. These restrictions or conditions also could have the effect of delaying completion of the merger or imposing additional costs on or limiting the revenues of the combined company following the merger, which could have a material adverse effect on the financial results of the combined company and/or cause either ETE or Southern Union to abandon the merger.  Southern Union can provide no assurance that the various closing conditions and required approvals will be met or obtained.

If the merger agreement is terminated, Southern Union may be obligated to reimburse ETE for costs incurred related to the merger and, under certain circumstances, pay a breakup fee to ETE. These costs could require Southern Union to seek loans or use Southern Union’s available cash that would have otherwise been available for operations, dividends or other general corporate purposes.

In certain circumstances, upon termination of the merger agreement, Southern Union would be responsible for reimbursing ETE for up to $54 million in expenses related to the transaction and may be obligated to pay a breakup fee to ETE of $181.3 million.

If the merger agreement is terminated, the expense reimbursements and the breakup fee required to be paid, if any, by Southern Union under the merger agreement may require Southern Union to seek loans or borrow amounts to enable it to pay these amounts to ETE. In either case, payment of these amounts would reduce the cash Southern Union has available for operations, dividends or other general corporate purposes. 

The failure to successfully combine the businesses of ETE and Southern Union in the expected time frame may adversely affect ETE’s future results, which may adversely affect the value of the ETE common units that Southern Union stockholders would receive in the merger.

The success of the merger will depend, in part, on the ability of ETE to realize the anticipated benefits from combining the businesses of ETE and Southern Union. To realize these anticipated benefits, ETE’s and Southern Union’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

ETE and Southern Union, including their respective subsidiaries, have operated and, until the completion of the merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect the combined company’s ability to maintain relationships with customers and employees after the merger or to achieve the anticipated benefits of the merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of ETE and Southern Union.

56

The pendency of the merger could materially adversely affect the future business and operations of Southern Union or result in a loss of Southern Union employees.

In connection with the pending merger, it is possible that some customers, suppliers and other persons with whom Southern Union has a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with Southern Union as a result of the merger, which could negatively impact revenues, earnings and cash flows of Southern Union, as well as the market price of shares of Southern Union common stock, regardless of whether the merger is completed. Similarly, current and prospective employees of Southern Union may experience uncertainty about their future roles with ETE and Southern Union following completion of the merger, which may materially adversely affect the ability of Southern Union to attract and retain key employees.

Failure to complete the merger could negatively impact the stock price of Southern Union and its future businesses and financial results.

If the merger is not completed, the ongoing business of Southern Union may be adversely affected and Southern Union will be subject to several risks and consequences, including the following:

·   under the merger agreement, Southern Union may be required, under certain circumstances, to pay ETE a breakup fee of $181.3 million and up to $54.0 million of ETE’s expenses;

·   Southern Union will be required to pay certain costs relating to the merger, whether or not the merger is completed, such as legal, accounting, financial advisor and printing fees;

·   Southern Union would not realize the expected benefits of the merger;

·   under the merger agreement, Southern Union is subject to certain restrictions on the conduct of its business prior to completing the merger which may adversely affect its ability to execute certain of its business strategies; and

·   matters relating to the merger may require substantial commitments of time and resources by Southern Union management, which could otherwise have been devoted to other opportunities that may have been beneficial to Southern Union as an independent company.

In addition, if the merger is not completed, Southern Union may experience negative reactions from the financial markets and from its customers and employees. Southern Union also could be subject to litigation related to any failure to complete the merger or to enforcement proceedings commenced against Southern Union to attempt to force it to perform its obligations under the merger agreement.

Pending litigation against ETE and Southern Union could result in an injunction preventing completion of the merger, the payment of damages in the event the merger is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

In connection with the merger, purported stockholders of Southern Union have filed several stockholder class action lawsuits against Southern Union, Merger Sub, ETE and the Southern Union Board in the District Courts of Harris County, Texas and in the Delaware Courts of Chancery. Among other remedies, the plaintiffs seek to enjoin the merger. If a final settlement is not reached, or if a dismissal is not obtained, these lawsuits could prevent or delay completion of the merger and result in substantial costs to ETE and Southern Union, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against Southern Union related to the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company’s business, financial condition or results of operations.

57

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

The following table presents information with respect to purchases during the three months ended June 30, 2011 made by Southern Union or any “affiliated purchaser” of Southern Union (as defined in Rule 10b-18(a)(3)) of equity securities that are registered pursuant to Section 12 of the Exchange Act.

	Total Number		Average
	of Shares		Price Paid
	Purchased (1)		per Share
Month Ended April 30, 2011		5,674	$	28.63
Month Ended May 31, 2011		363		29.67
Month Ended June 30, 2011		2,442		38.37
Total		8,479	$	31.48

______________

(1)  The total number of shares purchased includes:  (i) the surrender to the Company of 3,290 shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock awards and exercise of stock appreciation rights and (ii) 5,189 shares of common stock purchased in open-market transactions and held in various Company employee benefit plan trusts by the trustees using cash amounts deferred by the participants in such plans (and quarterly cash dividends issued by the Company on shares held in such plans).

ITEM 3.  Defaults Upon Senior Securities.

N/A

ITEM 4.  Reserved.

ITEM 5.  Other Information.

All information required to be reported on Form 8-K for the quarter ended June 30, 2011 was appropriately reported.

ITEM 6.  Exhibits.

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

2(a) Agreement and Plan of Merger, dated as of June 15, 2011, as Amended and Restated as of July 4, 2011 and July 19, 2011, by and between the Southern Union Company, Energy Transfer Equity, L.P. and Sigma Acquisition Corporation (Filed as Exhibit 2.1 to Southern Union’s Current Report on Form 8-K filed on July 20, 2011 and incorporated herein by reference.)

2(b) Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of January 26, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on January 30, 2006 and incorporated herein by reference.)

2(c) First Amendment to the Purchase and Sale Agreement between Southern Union Company and UGI Corporation, dated as of August 24, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(d) Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of February 15, 2006. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 17, 2006 and incorporated herein by reference.)

58

2(e) Limited Settlement Agreement between Southern Union Company, Narragansett Electric Company d/b/a National Grid, the Department of the Attorney General for the State of Rhode Island and the Rhode Island Department of Environmental Management, dated as of August 24, 2006. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

2(f) First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

3(a) Amended and Restated Certificate of Incorporation of Southern Union Company. (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference.)

3(b) By-Laws of Southern Union Company, as amended.  (Filed as Exhibit 3(b) to Southern Union’s Annual Report on Form 10-K  for the year ended December 31, 2009 and incorporated herein by reference.)

4(a) Specimen Common Stock Certificate.  (Filed as Exhibit 4(a) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1989 and incorporated herein by reference.)

4(b) Senior Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as Trustee (Filed as Exhibit 4.1 to Southern Union’s Current Report on Form 8-K dated February 15, 1994 and incorporated here-in by reference.)

4(c) Officers' Certificate dated January 31, 1994 setting forth the terms of the 7.60% Senior Debt Securities due 2024.  (Filed as Exhibit 4.2 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein by reference.)

4(d) Officer's Certificate of Southern Union Company dated November 3, 1999 with respect to 8.25% Senior Notes due 2029.  (Filed as Exhibit 99.1 to Southern Union's Current Report on Form 8-K filed on November 19, 1999 and incorporated herein by reference.)

4(e) Form of Supplemental Indenture No. 1, dated June 11, 2003, between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.5 to Southern Union’s Form 8-A/A dated June 20, 2003 and incorporated herein by reference.)

4(f) Supplemental Indenture No. 2, dated February 11, 2005, between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.4 to Southern Union’s Form 8-A/A dated February 22, 2005 and incorporated herein by reference.)

          4(g) Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (Filed as Exhibit 4-G to Southern Union’s Registration Statement on Form S-3 (No. 33-58297) and incorporated herein by reference.)

59

4(h) Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)

4(i) 2006 Series A Junior Subordinated Notes Due November 1, 2066 dated October 23, 2006. (Filed as Exhibit 4.2 to Southern Unions Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

4(j) Replacement Capital Covenant, dated as of October 23, 2006 by Southern Union Company, a Delaware corporation with its successors and assigns, in favor of and for the benefit of each Covered Debtor (as defined in the Covenant). (Filed as Exhibit 4.3 to Southern Union’s Current Report on Form 8-K/A filed on October 24, 2006 and incorporated herein by reference.)

          4(k) Southern Union is a party to other debt instruments, none of which authorizes the issuance of debt securities in an amount which exceeds 10% of the total assets of Southern Union.  Southern Union hereby agrees to furnish a copy of any of these instruments to the Commission upon request.

10(a) Seventh Amended and Restated Revolving Credit Agreement, dated as of May 20, 2011, among the Company, as borrower, and the lenders partythereto. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on May 24, 2011 and incorporated herein by reference.)

10(b) Amended and Restated Credit Agreement, dated as of August 3, 2010, among the Company, as borrower, and the lenders party thereto (Filed as Exhibit 10(b) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 and incorporated herein by reference.)

10(c) First Amendment to Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of August 6, 2008. (Filed as Exhibit 10(a) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

10(d) Construction and Term Loan Agreement between Citrus Corp., as borrower, and Pipeline Funding Company, LLC, as lender and administrative agent, dated as of February 5, 2008. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on February 8, 2008 and incorporated herein by reference.)

10(e) Amendment Number 1 to the Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 13, 2008. (Filed as Exhibit 10(d) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference.)

10(f) Amended and Restated Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial institutions listed therein and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of June 29, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 6, 2007 and incorporated herein by reference.)

10(g) Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipeline Company, LP and Trunkline LNG Company, LLC, as guarantors, the financial institutions listed therein and Hypo-Und Vereinsbank AG, New York Branch, as administrative agent, dated as of March 15, 2007. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 21, 2007 and incorporated herein by reference.)

60

        10(h) Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company and certain senior executive officers. (Filed as Exhibit 10(g) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)

10(i) Southern Union Company 1992 Long-Term Stock Incentive Plan, As Amended. (Filed as Exhibit 10(l) to Southern Union’s Annual Report on Form 10-K for the year ended June 30, 1998 and incorporated herein by reference.) *

10(j) Southern Union Company Director's Deferred Compensation Plan.  (Filed as Exhibit 10(g) to Southern Union's Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference.)

10(k) First Amendment to Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007. (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference.)

10(l) Southern Union Company Amended Supplemental Deferred Compensation Plan with Amendments.  (Filed as Exhibit 4 to Southern Union’s Form S-8 filed May 27, 1999 and incorporated herein by reference.) *

        10(m) Second Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-138524, filed on November 8, 2006 and incorporated herein by reference.) *

           10(n) Third Amended and Restated Southern Union Company 2003 Stock and Incentive Plan. (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on April 16, 2009 and incorporated herein by reference).*

         10(o) Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s Form 8-K dated January 3, 2007) and incorporated herein by reference.) *

10(p) Employment Agreement between Southern Union Company and George L. Lindemann, dated as of August 28, 2008.  (Filed as Exhibit 10(f) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(q) Employment Agreement between Southern Union Company and Eric D. Herschmann, dated as of August 28, 2008.  (Filed as Exhibit 10(g) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(r) Employment Agreement between Southern Union Company and Robert O. Bond, dated as of August 28, 2008.  (Filed as Exhibit 10(h) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(s) Employment Agreement between Southern Union Company and Monica M. Gaudiosi, dated as of August 28, 2008.  (Filed as Exhibit 10(i) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

         10(t) Second Amended and Restated Southern Union Company Executive Incentive Bonus Plan, dated March 25, 2010 (Filed as Appendix I to Southern Union’s proxy statement on Schedule 14A filed on March 26, 2006 and incorporate herein by reference.) *

61

10(u) Employment Agreement between Southern Union Company and Richard N. Marshall, dated as of August 28, 2008.  (Filed as Exhibit 10(j) to Southern Union Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference.) *

10(v) Form of Change in Control Severance Agreement, between Southern Union Company and certain Executives (filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on August 28, 2008 and incorporated herein by reference.) *

          10(w) Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(t) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference.)

          10(x) Certificate of Incorporation of Citrus Corp.  (Filed as Exhibit 10(q) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

          10(y) By-Laws of Citrus Corp., filed herewith.  (Filed as Exhibit 10(r) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006 and incorporated herein by reference.)

12 Ratio of earnings to fixed charges.  (Filed herewith as Exhibit 12.)

       14 Code of Ethics and Business Conduct. (Filed as Exhibit 14 to Southern Union’s Annual Report on Form 10-K filed on March 16, 2006 and incorporated herein by reference.)

31.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certificate by Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

32.2 Certificate by Chief Financial Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) promulgated under the Securities Exchange Act of 1934 and Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

  101.INS XBRL Instance Document  **

101.SCH XBRL Taxonomy Extension Schema Document  **

101.CAL	XBRL Taxonomy Calculation Linkbase Document  **
101.DEF	XBRL Taxonomy Extension Definitions Document  **

62

101.LAB	XBRL Taxonomy Label Linkbase Document  **
101.PRE	XBRL Taxonomy Presentation Linkbase Document  **

* Management contract or compensation plan or arrangement

** 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.

63

SIGNATURES

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 9, 2011	By /s/ GEORGE E. ALDRICH
	George E. Aldrich                                                                        Senior Vice President and Controller                                                                               (authorized officer and principal                                                                            accounting officer)

64

EX-12

Exhibit 12

SOUTHERN UNION COMPANY

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth the ratio of earnings to fixed charges for the Company on a historical basis for the six months ended June 30, 2011 and the years ended December 31, 2010, 2009, 2008, 2007 and 2006.  For the purpose of calculating such ratios, “earnings” consist of pre-tax income from continuing operations before income or loss from equity investees, adjusted to reflect distributed income from equity investments, and fixed charges, less capitalized interest.  “Fixed charges” consist of interest costs, amortization of debt discount, premiums and issuance costs and an estimate of interest implicit in rentals.  No adjustment has been made to earnings for the amortization of capital interest for the periods presented as such amount is immaterial.  Interest on unrecognized tax liabilities is excluded from the computation of fixed charges as it is recorded by the Company in income tax expense versus interest expense.

	6 Months Ended			Year Ended December 31,
	June 30, 2011			2010			2009			2008			2007			2006
	(In thousands)
FIXED CHARGES:
Interest Expense	$	107,572		$	210,008		$	191,022		$	204,272		$	202,403		$	202,513
Net amortization of debt discount, premium and
issuance expense		2,932			6,657			5,778			3,136			743			12,130
Capitalized Interest		513			6,646			25,747			18,963			14,708			5,492
Interest portion of rental expense		3,372			6,685			7,576			6,386			6,645			6,234
Total Fixed Charges	$	114,389		$	229,996		$	230,123		$	232,757		$	224,499		$	226,369
EARNINGS:
Consolidated pre-tax income from
continuing operations	$	164,665		$	349,677		$	251,480		$	399,926		$	323,970		$	326,330
Earnings of equity investments		(51,749	)		(105,415	)		(80,790	)		(75,030	)		(100,914	)		(141,370	)
Distributed income from equity investments		1,500			3,500			-			77,150			103,550			62,637
Capitalized interest		(513	)		(6,646	)		(25,747	)		(18,963	)		(14,708	)		(5,492	)
Total fixed charges (from above)		114,389			229,996			230,123			232,757			224,499			226,369
Earnings Available for Fixed Charges	$	228,292		$	471,112		$	375,066		$	615,840		$	536,397		$	468,474
Ratio of Earnings to Fixed Charges		2.0			2.0			1.6			2.6			2.4			2.1

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

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

I, George L. Lindemann, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  August 9, 2011

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board and

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

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

I, Richard N. Marshall, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  August 9, 2011

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-Q of Southern Union Company (the “Company”) for the quarter ended June 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George L. Lindemann, Chairman of the Board and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board and

Chief Executive Officer

August 9, 2011

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

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Form 10-Q of Southern Union Company (the “Company”) for the quarter ended June 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard N. Marshall, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, except as otherwise noted under Item 9A therein, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

August 9, 2011

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

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

XML



Derivative Instrument and Hedging Activities 2 (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	$ 9,665	$ 16,931
Derivative Fair Value Of Derivative Liability	78,166	91,177
Gathering And Processing [Member] | Derivative Instruments Liabilitiy [Member] | Designated As Hedging Instrument [Member] | Natural Gas Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	9,275	16,459
Derivative Fair Value Of Derivative Liability	0	0
Gathering And Processing [Member] | Derivative Instruments Liabilitiy [Member] | Designated As Hedging Instrument [Member] | NGL Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	0	0
Derivative Fair Value Of Derivative Liability	2,408	0
Gathering And Processing [Member] | Derivative Instruments Liabilitiy [Member] | Nondesignated [Member] | NGL Processing Spread Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	0	0
Derivative Fair Value Of Derivative Liability	26,716	29,057
Distribution [Member] | Derivative Instruments Liabilitiy [Member] | Nondesignated [Member] | Natural Gas Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	100	234
Derivative Fair Value Of Derivative Liability	13,098	34,968
Derivative Instruments Liabilitiy [Member] | Designated As Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	0	0
Derivative Fair Value Of Derivative Liability	23,353	19,694
Gathering And Processing [Member] | Prepayments And Other Assets [Member] | Nondesignated [Member] | Other Derivative Instruments [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	9	133
Derivative Fair Value Of Derivative Liability	0	0
Gathering And Processing [Member] | Deferred Credits [Member] | Designated As Hedging Instrument [Member] | Natural Gas Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	230	0
Derivative Fair Value Of Derivative Liability	0	0
Gathering And Processing [Member] | Deferred Credits [Member] | Designated As Hedging Instrument [Member] | NGL Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	0	0
Derivative Fair Value Of Derivative Liability	836	0
Distribution [Member] | Deferred Credits [Member] | Nondesignated [Member] | Natural Gas Price Swaps [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	51	105
Derivative Fair Value Of Derivative Liability	716	2,806
Deferred Credits [Member] | Designated As Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	0	0
Derivative Fair Value Of Derivative Liability	11,039	4,652
Designated As Hedging Instrument [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	9,505	16,459
Derivative Fair Value Of Derivative Liability	37,636	24,346
Nondesignated [Member]
Derivatives Fair Value Line Items
Derivative Fair Value Of Derivative Asset	160	472
Derivative Fair Value Of Derivative Liability	$ 40,530	$ 66,831

XML



CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 3,013,000	$ 3,299,000
Accounts receivable, net of allowances of $4,467 and $3,321, respectively	262,293,000	310,006,000
Accounts receivable - affiliates	7,863,000	10,747,000
Inventories	174,040,000	226,875,000
Deferred natural gas purchases	13,396,000	85,138,000
Natural gas imbalances - receivable	72,006,000	52,141,000
Prepayments and other assets	70,241,000	67,535,000
Total current assets	602,852,000	755,741,000
Property, plant and equipment:
Plant in service	7,020,306,000	6,957,989,000
Construction work in progress	165,126,000	120,264,000
Property, Plant and Equipment, Gross	7,185,432,000	7,078,253,000
Less accumulated depreciation and amortization	1,487,919,000	1,373,794,000
Net property, plant and equipment	5,697,513,000	5,704,459,000
Deferred charges:
Regulatory assets	63,022,000	66,216,000
Deferred charges	64,731,000	66,929,000
Total deferred charges	127,753,000	133,145,000
Unconsolidated investments	1,587,863,000	1,538,548,000
Goodwill	89,227,000	89,227,000
Loan to unconsolidated investments	72,000,000
Other	84,861,000	17,423,000
Total assets	8,190,069,000	8,238,543,000
Stockholders equity:
Common stock, $1 par value; 200,000 shares authorized; 125,975 and 125,839 shares issued, respectively	125,975,000	125,839,000
Premium on capital stock	1,927,356,000	1,920,622,000
Less treasury stock: 1,240 and 1,230 shares, respectively, at cost	(30,809,000)	(30,532,000)
Less common stock held in trust: 573 and 597 shares, respectively	(10,543,000)	(10,857,000)
Deferred compensation plans	10,543,000	10,857,000
Accumulated other comprehensive loss	(51,507,000)	(40,157,000)
Retained earnings	634,236,000	551,210,000
Total stockholders' equity	2,605,251,000	2,526,982,000
Long-term debt obligations	2,705,534,000	3,520,906,000
Total capitalization	5,310,785,000	6,047,888,000
Current liabilities:
Long-term debt due within one year	816,272,000	1,083,000
Notes payable	195,479,000	297,051,000
Accounts payable and accrued liabilities	198,357,000	218,531,000
Federal, state and local taxes payable	35,824,000	35,235,000
Accrued interest	37,397,000	37,464,000
Natural gas imbalances - payable	152,211,000	178,087,000
Derivative instruments	56,200,000	67,026,000
Other	124,997,000	137,221,000
Total current liabilities	1,616,737,000	971,698,000
Deferred credits	203,202,000	205,094,000
Accumulated deferred income taxes	1,059,345,000	1,013,863,000
Commitments and contingencies
Total stockholders' equity and liabilities	$ 8,190,069,000	$ 8,238,543,000

XML



PARENTHETICAL DISCLOSURE OF CONDENSED CONSOLIDATED BALANCE SHEET (USD $) In Thousands, except Per Share data	Jun. 30, 2011	Dec. 31, 2010
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 4,467	$ 3,321
Stockholders equity:
Common stock, par value	$ 1	$ 1
Common stock, shares authorized	200,000	200,000
Common stock, shares issued	125,975	125,839
Treasury stock, shares	1,240	1,230
Common stock, Shares Held in Employee Trust	573	597

XML



Fair Value Measurement (Details) (Fair Value Measurements Recurring [Member], USD $) In Thousands	Jun. 30, 2011
Fair Value Line Items [Abstract]
Commodity derivatives	$ 9
Long-term investments	1,027
Total	1,036
Commodity derivatives	34,118
Interest-rate swap derivatives	34,392
Total	68,510
Level 1 [Member]
Fair Value Line Items [Abstract]
Commodity derivatives	0
Long-term investments	1,027
Total	1,027
Commodity derivatives	0
Interest-rate swap derivatives	0
Total	0
Level 2 [Member]
Fair Value Line Items [Abstract]
Commodity derivatives	9
Long-term investments	0
Total	9
Commodity derivatives	34,118
Interest-rate swap derivatives	34,392
Total	68,510
Level 3 [Member]
Fair Value Line Items [Abstract]
Commodity derivatives	0
Long-term investments	0
Total	0
Commodity derivatives	0
Interest-rate swap derivatives	0
Total	$ 0

XML



New Accounting Principles and Other Matters (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Summary of Significant Accounting Policies and Other Matters

2. New Accounting Principles

Accounting Principles Not Yet Adopted. In June 2011, the FASB issued authoritative guidance that changes how a company may present comprehensive income. The guidance allows entities to elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive statements and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted. The Company does not expect the guidance to materially impact its consolidated financial statements as the guidance only requires a change in the placement of previously disclosed information.

In May 2011, the FASB issued authoritative guidance on fair value measurements that clarifies some existing concepts, eliminates wording differences between GAAP and International Financial Reporting Standards (IFRS), and in some limited cases, changes some principles to achieve convergence between GAAP and IFRS. The guidance provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS and also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. The guidance is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact of this guidance, but does not expect it will materially impact its consolidated financial statements.

XML



Document And Entity Information (USD $)	6 Months Ended
	Jun. 30, 2011	Aug. 05, 2011	Jun. 30, 2010
Document Information Line Items
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Entity Information Line Items
Entity Registrant Name	Southern Union Co
Entity Central Index Key	0000203248
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,529,540,437
Entity Common Stock, Shares Outstanding		124,745,576

XML



Taxes on Income 2 Narrative (Details)	6 Months Ended
	Jun. 30, 2011
Income Tax Disclosure [Abstract]
Statutory rate	35.00%
Dividends received deduction	80.00%

XML



Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

ScheduleOfComprehensiveIncomeLossTableTextBlock

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010
				(In thousands)
Net earnings			$	59,773	$	74,889	$	120,435	$	131,349
	Change in fair value of interest rate hedges, net of tax of
		$(6,891), $(1,308), $(7,757) and $(3,614), respectively		(11,587)		(1,945)		(12,991)		(5,375)
	Reclassification of unrealized loss on interest rate hedges
		into earnings, net of tax of $2,253, $2,250, $4,481
		and $4,554, respectively		3,362		3,357		6,685		6,803
	Change in fair value of commodity hedges, net of tax of $194,
		$(390), $(365) and $9,613, respectively		344		(690)		(649)		17,061
	Reclassification of unrealized gain on commodity hedges
		into earnings, net of tax of $(1,678), $(1,830), $(3,310) and $(2,272), respectively		(2,977)		(3,247)		(5,874)		(4,032)
	Reclassification of net actuarial loss and prior service credit
		relating to pension and other postretirement benefits into
		earnings, net of tax of $568, $551, $1,142
		and $1,102, respectively		706		722		1,407		1,442
	Change in other comprehensive income from equity
		investments, net of tax of $21, $22, $43 and $44, respectively		37		35		72		71
Total other comprehensive income (loss)				(10,115)		(1,768)		(11,350)		15,970
Total comprehensive income			$	49,658	$	73,121	$	109,085	$	147,319

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

		June 30,		December 31,
		2011		2010
		(In thousands)
Interest rate hedges, net		$	(23,538)	$	(17,232)
Commodity hedges, net			4,005		10,528
Benefit plans:
	Net actuarial loss and prior service costs, net - pensions		(30,372)		(32,982)
	Net actuarial gain and prior service credit, net - other postretirement benefits		1,004		2,207
Equity investments, net			(2,606)		(2,678)
Total Accumulated other comprehensive income, net of tax		$	(51,507)	$	(40,157)

XML



Taxes on Income 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income Tax Disclosure [Abstract]
Income tax expense	$ 25,588	$ 28,609	$ 44,230	$ 59,418
Effective tax rate	30.00%	28.00%	27.00%	31.00%

XML



Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Accumulated Other Comprehensive Loss

6. Comprehensive Income (Loss)

The table below provides an overview of Comprehensive income (loss) for the periods presented.

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2011		2010		2011		2010
				(In thousands)
Net earnings			$	59,773	$	74,889	$	120,435	$	131,349
	Change in fair value of interest rate hedges, net of tax of
		$(6,891), $(1,308), $(7,757) and $(3,614), respectively		(11,587)		(1,945)		(12,991)		(5,375)
	Reclassification of unrealized loss on interest rate hedges
		into earnings, net of tax of $2,253, $2,250, $4,481
		and $4,554, respectively		3,362		3,357		6,685		6,803
	Change in fair value of commodity hedges, net of tax of $194,
		$(390), $(365) and $9,613, respectively		344		(690)		(649)		17,061
	Reclassification of unrealized gain on commodity hedges
		into earnings, net of tax of $(1,678), $(1,830), $(3,310) and $(2,272), respectively		(2,977)		(3,247)		(5,874)		(4,032)
	Reclassification of net actuarial loss and prior service credit
		relating to pension and other postretirement benefits into
		earnings, net of tax of $568, $551, $1,142
		and $1,102, respectively		706		722		1,407		1,442
	Change in other comprehensive income from equity
		investments, net of tax of $21, $22, $43 and $44, respectively		37		35		72		71
Total other comprehensive income (loss)				(10,115)		(1,768)		(11,350)		15,970
Total comprehensive income			$	49,658	$	73,121	$	109,085	$	147,319

The table below provides an overview of the components in Accumulated other comprehensive loss as of the dates indicated.

		June 30,		December 31,
		2011		2010
		(In thousands)
Interest rate hedges, net		$	(23,538)	$	(17,232)
Commodity hedges, net			4,005		10,528
Benefit plans:
	Net actuarial loss and prior service costs, net - pensions		(30,372)		(32,982)
	Net actuarial gain and prior service credit, net - other postretirement benefits		1,004		2,207
Equity investments, net			(2,606)		(2,678)
Total Accumulated other comprehensive income, net of tax		$	(51,507)	$	(40,157)

XML



Debt Obligations (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Schedule Of Debt Instruments Text Block

		June 30, 2011				December 31, 2010
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(In thousands)
Long-Term Debt Obligations:
Southern Union:
7.60% Senior Notes due 2024		$	359,765	$	428,300	$	359,765	$	392,144
8.25% Senior Notes due 2029			300,000		377,403		300,000		332,922
7.24% to 9.44% First Mortgage Bonds
	due 2020 to 2027		19,500		23,558		19,500		21,473
7.20% Junior Subordinated Notes due 2066			600,000		575,280		600,000		609,743
Term Loan due 2013			250,000		252,491		250,000		249,915
Note Payable			8,019		8,019		8,297		8,297
			1,537,284		1,665,051		1,537,562		1,614,494
Panhandle:
6.05% Senior Notes due 2013			250,000		273,260		250,000		268,988
6.20% Senior Notes due 2017			300,000		346,413		300,000		322,893
8.125% Senior Notes due 2019			150,000		183,813		150,000		169,671
7.00% Senior Notes due 2029			66,305		70,068		66,305		69,911
7.00% Senior Notes due 2018			400,000		472,416		400,000		442,120
Term Loans due 2012			815,391		808,481		815,391		799,084
Net premiums on long-term debt			2,826		2,826		2,731		2,731
			1,984,522		2,157,277		1,984,427		2,075,398
Total Long-Term Debt Obligations			3,521,806		3,822,328		3,521,989		3,689,892
Credit Facilities			195,479		195,487		297,051		301,312
Total consolidated debt obligations			3,717,285	$	4,017,815		3,819,040	$	3,991,204
	Less current portion of long-term debt		816,272				1,083
	Less short-term debt		195,479				297,051
Total long-term debt		$	2,705,534			$	3,520,906

XML



Comprehensive Income (Loss) 3 (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Comprehensive Income Loss [Line Items]
Interest rate hedges, net	$ (23,538)	$ (17,232)
Commodity hedges, net	4,005	10,528
Benefit Plans [Abstract]
Net actuarial loss and prior service costs, net - pensions	(30,372)	(32,982)
Net actuarial gain and prior service credit, net- other postretirement benefits	1,004	2,207
Equity investments, net	(2,606)	(2,678)
Total Accumulated other comprehensive income, net of tax	$ (51,507)	$ (40,157)

XML



Unconsolidated Investments 1 (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Schedule Of Equity Method Investments Line Items
Unconsolidated investments	$ 1,587,863	$ 1,538,548
Citrus [Member]
Schedule Of Equity Method Investments Line Items
Unconsolidated investments	1,561,664	1,510,847
Other Unconsolidated Investments [Member]
Schedule Of Equity Method Investments Line Items
Unconsolidated investments	$ 26,199	$ 27,701

XML



Unconsolidated Investments (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Equity Method Investments Text Block

	June 30,		December 31,
	2011		2010
		(In thousands)
Citrus (1)	$	1,561,664	$	1,510,847
Other		26,199		27,701
	$	1,587,863	$	1,538,548

___________________

(1) See Note 3 – ETE Merger for information regarding the Company's intent for its ownership interest in Citrus to be merged with an ETP subsidiary.

Unconsolidated Investments Summarized Financial Information Table [Text Block]

	Three Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	194,361	$	2,506	$	140,572	$	5,823
Operating income		118,716		705		77,323		3,297
Net earnings		47,173		689		46,460		3,101
	Six Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	308,246	$	5,082	$	254,711	$	11,684
Operating income		168,598		1,637		129,694		6,482
Net earnings		96,526		1,844		76,087		6,270

XML



Fair Value Measurement

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Fair Value Measurement

11. 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 dates indicated.

		Fair Value		Fair Value Measurements at June 30, 2011
		as of		Using Fair Value Hierarchy
		June 30, 2011		Level 1		Level 2		Level 3
		(In thousands)
Assets:
	Commodity derivatives	$	9	$	-	$	9	$	-
	Long-term investments		1,027		1,027		-		-
	Total	$	1,036	$	1,027	$	9	$	-
Liabilities:
	Commodity derivatives	$	34,118	$	-	$	34,118	$	-
	Interest-rate swap derivatives		34,392		-		34,392		-
	Total	$	68,510	$	-	$	68,510	$	-

The Company's Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes. 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, 2011 or December 31, 2010.

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.

XML



New Accounting Principles and Other Matters

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Summary of Significant Accounting Policies and Other Matters

2. New Accounting Principles

Accounting Principles Not Yet Adopted. In June 2011, the FASB issued authoritative guidance that changes how a company may present comprehensive income. The guidance allows entities to elect to present items of net income and other comprehensive income in one continuous statement or in two separate, but consecutive statements and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.  The guidance is effective as of the beginning of a fiscal year that begins after December 15, 2011 and interim and annual periods thereafter, with early adoption permitted. The Company does not expect the guidance to materially impact its consolidated financial statements as the guidance only requires a change in the placement of previously disclosed information.

In May 2011, the FASB issued authoritative guidance on fair value measurements that clarifies some existing concepts, eliminates wording differences between GAAP and International Financial Reporting Standards (IFRS), and in some limited cases, changes some principles to achieve convergence between GAAP and IFRS. The guidance provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and IFRS and also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. The guidance is effective for periods beginning after December 15, 2011. The Company is currently evaluating the impact of this guidance, but does not expect it will materially impact its consolidated financial statements.

XML



ETE Merger (Details) (USD $)	0 Months Ended
	Jul. 19, 2011
Plan Of Merger [Line Items]
Percentages Of Shares Cash	at least 50 percent, and no more than 60 percent
Percentage Of Shares Shares	in the event that holders of more than 60 percent of the Outstanding Shares elect to receive cash) and at least 40 percent, and no more than 50 percent
Value Outstanding Share	$ 44.25
Common Units Per Outstanding Share	1.0
Contract Termination Fee	181,300,000
Obligated Maximum Merger Costs	54,000,000
Citrus [Member]
Plan Of Merger [Line Items]
Percentage Owned By Equity Investment	100.00%
Total Merger Amount	2,000,000,000
Merger Cash	1,895,000,000
Merger Common Units	105,000,000
Maximum Contribution Equity Interest Merger	$ 1,450,000,000

XML



Employee Benefits

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Benefits

8. Benefits

Components of Net Periodic Benefit Cost. The following table sets forth the components of net periodic benefit cost of the Company's pension and postretirement benefit plans for the periods presented.

		Pension Benefits				Other Postretirement Benefits
		Three Months Ended June 30,				Three Months Ended June 30,
		2011		2010		2011		2010
			(In thousands)
Service cost		$	935	$	768	$	881	$	793
Interest cost			2,525		2,509		1,446		1,409
Expected return on plan assets			(2,647)		(2,337)		(1,450)		(1,269)
Prior service cost (credit)
	amortization		147		138		(453)		(411)
Actuarial loss (gain)
	amortization		1,984		1,996		(403)		(451)
			2,944		3,074		21		71
Regulatory adjustment (1)			191		52		666		666
Net periodic benefit cost		$	3,135	$	3,126	$	687	$	737
		Pension Benefits				Other Postretirement Benefits
		Six Months Ended June 30,				Six Months Ended June 30,
		2011		2010		2011		2010
			(In thousands)
Service cost		$	1,870	$	1,535	$	1,761	$	1,586
Interest cost			5,050		5,019		2,892		2,819
Expected return on plan assets			(5,293)		(4,674)		(2,899)		(2,311)
Prior service cost (credit)
	amortization		294		276		(906)		(823)
Actuarial loss (gain)
	amortization		3,967		3,993		(806)		(901)
			5,888		6,149		42		370
Regulatory adjustment (1)			383		157		1,332		1,332
Net periodic benefit cost		$	6,271	$	6,306	$	1,374	$	1,702

________________________________

• 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.

XML



Reportable Segments

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Reportable Segments

13. Reportable Segments

The Company's 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. 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.

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 evaluates operational and financial segment performance based on several factors, of which the primary financial measure is EBIT, a non-GAAP measure. The Company defines EBIT as Net earnings available for common stockholders, adjusted for the following:

• items that do not impact net earnings, such as extraordinary items, discontinued operations and the impact of changes in accounting principles;
• income taxes;
• interest;
• dividends on preferred stock; and
• loss on extinguishment of preferred stock.

EBIT 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.

Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. There were no material intersegment revenues during the three- and six-month periods ended June 30, 2011 and 2010.

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

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2011		2010		2011		2010
				(In thousands)
Operating revenues from external customers:
	Transportation and Storage			$	189,760	$	187,090	$	392,054	$	373,765
	Gathering and Processing				328,515		282,707		552,167		543,567
	Distribution				109,076		99,711		425,649		407,972
		Total segment operating revenues			627,351		569,508		1,369,870		1,325,304
	Corporate and other activities				4,256		3,588		8,559		6,786
				$	631,607	$	573,096	$	1,378,429	$	1,332,090
Depreciation and amortization:
	Transportation and Storage			$	31,963	$	30,896	$	64,237	$	60,073
	Gathering and Processing				18,065		17,971		35,852		35,291
	Distribution				8,407		7,967		16,814		15,923
		Total segment depreciation and amortization			58,435		56,834		116,903		111,287
	Corporate and other activities				860		725		1,719		1,466
				$	59,295	$	57,559	$	118,622	$	112,753
Earnings from unconsolidated investments:
	Transportation and Storage			$	24,852	$	25,748	$	50,883	$	42,994
	Gathering and Processing				(158)		1,395		30		2,380
	Corporate and other activities				354		399		836		746
				$	25,048	$	27,542	$	51,749	$	46,120
Segment performance:
	Transportation and Storage EBIT			$	117,495	$	111,246	$	239,593	$	213,671
	Gathering and Processing EBIT				21,333		40,526		9,104		47,081
	Distribution EBIT				3,374		6,865		26,941		35,710
		Total segment EBIT			142,202		158,637		275,638		296,462
	Corporate and other activities				(1,908)		297		(469)		617
	Interest expense				54,933		55,436		110,504		106,312
	Federal and state income taxes				25,588		28,609		44,230		59,418
	Net earnings				59,773		74,889		120,435		131,349
	Preferred stock dividends				-		2,170		-		4,341
	Loss on extinguishment of preferred stock				-		3,295		-		3,295
		Net earnings available for common
			stockholders	$	59,773	$	69,424	$	120,435	$	123,713
				June 30,		December 31,
				2011		2010
				(In thousands)
Total assets:
	Transportation and Storage			$	5,281,414	$	5,224,992
	Gathering and Processing				1,740,188		1,700,598
	Distribution				989,680		1,135,352
		Total segment assets			8,011,282		8,060,942
	Corporate and other activities				178,787		177,601
	Total assets			$	8,190,069	$	8,238,543
				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2011		2010		2011		2010
				(In thousands)
Expenditures for long-lived assets:
	Transportation and Storage			$	28,911	$	25,886	$	39,169	$	56,257
	Gathering and Processing				20,903		15,823		56,513		41,706
	Distribution				13,447		9,151		20,409		16,255
		Total segment expenditures for long-lived
			assets		63,261		50,860		116,091		114,218
	Corporate and other activities				1,321		4,166		1,904		6,281
		Total expenditures for long-lived assets (1)		$	64,582	$	55,026	$	117,995	$	120,499

_______________________

• Related cash impact includes the net reduction in capital accruals totaling $10.4million and $7.9million for the three-month periods ended June 30, 2011 and 2010, respectively. Related cash impact includes the net reduction in capital accruals totaling $26 million and $(7.9)million for the six-month periods ended June 30, 2011 and 2010, respectively.

XML



Taxes on Income

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Taxes on Income

9. Taxes on Income

The following table summarizes the Company's income taxes for the periods presented.

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)
Income tax expense	$	25,588		$	28,609		$	44,230		$	59,418
Effective tax rate		30	%		28	%		27	%		31	%

The EITR is generally lower than the U.S. federal income tax statutory rate of 35 percent primarily due to the 80 percent dividends received deduction for the anticipated receipt of dividends associated with earnings from the Company's unconsolidated investment in Citrus.

XML



Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Environmental Liabilities Table [Text Block]

	June 30,		December 31,
	2011		2010
	(In thousands)
Current	$	5,890	$	10,648
Noncurrent		15,517		11,920
Total environmental liabilities	$	21,407	$	22,568

XML



Debt Obligations

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Debt Obligations

7. Debt Obligations

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

		June 30, 2011				December 31, 2010
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(In thousands)
Long-Term Debt Obligations:
Southern Union:
7.60% Senior Notes due 2024		$	359,765	$	428,300	$	359,765	$	392,144
8.25% Senior Notes due 2029			300,000		377,403		300,000		332,922
7.24% to 9.44% First Mortgage Bonds
	due 2020 to 2027		19,500		23,558		19,500		21,473
7.20% Junior Subordinated Notes due 2066			600,000		575,280		600,000		609,743
Term Loan due 2013			250,000		252,491		250,000		249,915
Note Payable			8,019		8,019		8,297		8,297
			1,537,284		1,665,051		1,537,562		1,614,494
Panhandle:
6.05% Senior Notes due 2013			250,000		273,260		250,000		268,988
6.20% Senior Notes due 2017			300,000		346,413		300,000		322,893
8.125% Senior Notes due 2019			150,000		183,813		150,000		169,671
7.00% Senior Notes due 2029			66,305		70,068		66,305		69,911
7.00% Senior Notes due 2018			400,000		472,416		400,000		442,120
Term Loans due 2012			815,391		808,481		815,391		799,084
Net premiums on long-term debt			2,826		2,826		2,731		2,731
			1,984,522		2,157,277		1,984,427		2,075,398
Total Long-Term Debt Obligations			3,521,806		3,822,328		3,521,989		3,689,892
Credit Facilities			195,479		195,487		297,051		301,312
Total consolidated debt obligations			3,717,285	$	4,017,815		3,819,040	$	3,991,204
	Less current portion of long-term debt		816,272				1,083
	Less short-term debt		195,479				297,051
Total long-term debt		$	2,705,534			$	3,520,906

The fair value of the Company's term loans and credit facilities as of June 30, 2011 and December 31, 2010 were determined using the market approach, which utilized 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, 2011 and December 31, 2010 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. 

Interest Rate Swaps.The Company has entered into 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 10 – Derivative Instruments and Hedging Activities – Interest Rate Contracts – Interest Rate Swaps for more information regarding these swap agreements.

Credit Facilities.During the second quarter of 2011, the Company entered into the Seventh Amended and Restated Revolving Credit Agreement with certain banks in the amount of $550 million (2011 Revolver).  The 2011 Revolver is an amendment, restatement and refinancing of the Company's $550 million Sixth Amended and Restated Revolving Credit Agreement (Revolver), which was otherwise scheduled to mature on May 28, 2013.  The 2011 Revolver will mature on May 20, 2016.  Borrowings under the 2011 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 2011 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 2011 Revolver at June 30, 2011 were LIBOR plus 162.5 basis points and 25 basis points, respectively.

XML



Derivative Instrument and Hedging Activities 4 Parentheticals (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Cash Flow Hedges Tax [Abstract]
Change in fair value of interest rate hedges tax	$ 6,891,000	$ 1,308,000	$ 7,757,000	$ 3,614,000
Reclassification of unrealized loss (gain) on interest rate hedges tax	2,253,000	2,250,000	4,481,000	4,554,000
Commodity Contracts Gathering and Processing Tax [Abstract]
Change in fair value of commodity hedges tax	(194,000)	390,000	365,000	(9,613,000)
Relcassification of unrealized (gain) loss on commodity hedges into earnings tax	1,678,000	1,830,000	3,310,000	2,272,000
Strategic Hedges [Abstract]
DerivativeCashReceivedOnHedge	7,300,000	9,000,000	16,800,000	20,000,000
Unrealized (gain) loss on commodity derivatives	$ (300,000)	$ (22,300,000)	$ 14,413,000	$ (16,654,000)

XML



CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Common Stock Held In Trust [Member]	Deferred Compensation, Share-based Payments [Member]	Accumulated Other Comprehensive Income [Member]	Retained Earnings [Member]
Beginning Balance at Dec. 31, 2010	$ 2,526,982	$ 125,839	$ 1,920,622	$ (30,532)	$ (10,857)	$ 10,857	$ (40,157)	$ 551,210
Comprehensive income:
Net earnings	120,435							120,435
Net change in other comprehensive loss	(11,350)						(11,350)
Comprehensive income	109,085
Common stock dividends declared	(37,409)							(37,409)
Share-based compensation	4,899		4,899
Restricted stock issuances	0	7	(7)	0
Exercise of stock options	1,694	129	1,842	(277)
Contributions to Trust	0	0	0	0	(355)	355	0	0
Disbursements from Trust	0				669	(669)
Ending balance at Jun. 30, 2011	$ 2,605,251	$ 125,975	$ 1,927,356	$ (30,809)	$ (10,543)	$ 10,543	$ (51,507)	$ 634,236

XML



ETE Merger

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

ETE Merger

3. ETE Merger

On July 19, 2011, the Company entered into a Second Amended and Restated Agreement and Plan of Merger (Second Amended Merger Agreement) with ETE and Sigma Acquisition Corporation, a wholly-owned subsidiary of ETE (Merger Sub).  The Second Amended Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by the Company, ETE and Merger Sub on June 15, 2011 as amended on July 4, 2011.  The Second Amended Merger Agreement provides for the merger of Merger Sub with and into the Company (Merger), with the Company continuing as the surviving corporation in the Merger.  As a result of the Merger, the Company will become a wholly-owned subsidiary of ETE.  The Merger is expected to close in the first quarter of 2012, subject to stockholder approval and certain other regulatory approvals.

Under the terms of the Second Amended Merger Agreement, at least 50 percent, and no more than 60 percent, of the shares of common stock of the Company issued and outstanding immediately prior to the effective time of the Merger (Outstanding Shares) will be cancelled and converted into the right to receive cash in the amount of $44.25 perOutstanding Share (subject to reduction of that amount of cash perOutstanding Share, and supplementation with ETE Common Units, in the event that holders of more than 60 percent of the Outstanding Shares elect to receive cash) and at least 40 percent, and no more than 50 percent of the Outstanding Shares will be cancelled and converted into the right to receive 1.0 ETE Common Units perOutstanding Share (subject to reduction of that number of ETE Common Units perOutstanding Share, and supplementation with cash, in the event that holders of more than 50 percent of the Outstanding Shares elect to receive ETE Common Units).

 On July 19, 2011, ETE entered into an amended and restated agreement and plan of merger (Citrus Merger Agreement) with Energy Transfer Partners , L.P. (ETP). Pursuant to the Citrus Merger Agreement, immediately prior to the effective time of the Merger, ETE will assign and Southern Union will assume the benefits and obligations of ETE under the Citrus Merger Agreement. Under the Citrus Merger Agreement, it is anticipated that Southern Union will cause the contribution to ETP of its 50 percent interest in Citrus Corp., which owns 100 percent of Florida Gas and is currently jointly owned by Southern Union and El Paso Corporation (Citrus Merger). The Citrus Merger will be effected through the merger of CrossCountry Energy, LLC, a Delaware limited liability company and wholly-owned subsidiary of Southern Union that indirectly owns a 50 percent interest in Citrus Corp., with and into Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of ETP. In exchange for the interest in Citrus Corp., Southern Union will receive approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP common units, with the value of the ETP common units based on the volume-weighted average trading price for the ten consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Merger.  Immediately prior to the effective time of the Merger, Southern Union will contribute to Merger Sub the funds it receives pursuant to the Citrus Merger (not to exceed $1.45 billion) in exchange for an equity interest in Merger Sub proportionate to its deemed share, which means the fraction (i) the numerator of which is the amount, if any, contributed by Southern Union to Merger Sub pursuant to the Second Amended Merger Agreement and (ii) the denominator of which is the aggregate value of the merger consideration of the Merger, valuing the ETE common units based upon the volume weighted average price of the ETE common units for the five trading days ending on the trading day immediately preceding the effective time of the Merger.

The Second Amended Merger Agreement contains certain termination rights for the Company and ETE. In certain circumstances, upon termination of the Second Amended Merger Agreement, the Company or ETE, as applicable: (i) will be required to pay a termination fee of $181.3 million to the other and (ii) may be obligated to pay the other's Merger costs and expenses in an amount not to exceed $54 million.

Consummation of the merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended Merger Agreement by the stockholders of the Company, (ii) the expiration of the waiting period applicable to the merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, which expiration occurred on July 28, 2011, (iii) the receipt of required approvals from the FERC, the MPSC and, if necessary, the MDPU, (iv) the effectiveness of an ETE registration statement on Form S-4 relating to the ETE common units to be issued in the merger, and (v) the absence of any law, injunction, judgment or ruling prohibiting or restraining the merger or making the consummation of the merger illegal.

On July 13, 2011, the Company and ETE filed a joint application with the MPSC, requesting an order from the MPSC authorizing the Company to take certain actions to allow ETE to acquire the equity interests of the Company, including its subsidiaries. On July 11, 2011, as amended July 26, 2011, ETE filed a registration statement on Form S-4 relating to the registration of the ETE common units to be issued in the merger.

The Company has made certain customary representations and warranties and covenants in the Second Amended Merger Agreement, including without limitation covenants regarding: (i) the conduct of the business of the Company prior to the consummation of the merger, (ii) the calling and holding of a meeting of the Company's stockholders for the purpose of obtaining its required stockholder approval and (iii) the use of reasonable best efforts to cause the merger to be consummated.

XML



Unconsolidated Investments 3 Narrative (Details) (USD $)	6 Months Ended		3 Months Ended		6 Months Ended		0 Months Ended	1 Months Ended
	Jun. 30, 2011	Apr. 30, 2011	Jun. 30, 2011 Citrus [Member]	Jun. 30, 2010 Citrus [Member]	Jun. 30, 2011 Citrus [Member]	Jun. 30, 2010 Citrus [Member]	May 02, 2011 Florida Gas [Member]	Jan. 27, 2011 Florida Gas [Member]
Notes to Financial Statements [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Equity Method Investment, Dividends or Distributions			$ 0	$ 0	$ 0	$ 0
Estimated Cost		2,480,000,000
Years Firm Transportation Service Agreements	25
Contracted Capacity	74
Loan to unconsolidated investments	72,000,000
Promissory Note with Unconsolidated Investment	150,000,000
Promissory Note Interest Rate	one-month Eurodollar rate plus a credit spread of 1.5
Proceeds From Legal Settlements								82,700,000
Interest Awarded							$ 8,000,000

XML



Fair Value Measurement (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

ScheduleOfFairValueAssetsAndLiabilitiesMeasuredOnRecurringBasisTableTextBlock

		Fair Value		Fair Value Measurements at June 30, 2011
		as of		Using Fair Value Hierarchy
		June 30, 2011		Level 1		Level 2		Level 3
		(In thousands)
Assets:
	Commodity derivatives	$	9	$	-	$	9	$	-
	Long-term investments		1,027		1,027		-		-
	Total	$	1,036	$	1,027	$	9	$	-
Liabilities:
	Commodity derivatives	$	34,118	$	-	$	34,118	$	-
	Interest-rate swap derivatives		34,392		-		34,392		-
	Total	$	68,510	$	-	$	68,510	$	-

XML



Reportable Segments 2 Narrative (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Segment Reporting Information Line Items
Material intersegment revenues	$ 0	$ 0	$ 0	$ 0

XML



Stockholders' Equity (Details) (USD $) In Thousands, except Per Share data	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Dividends [Line Items]
Shareholder Record Date	Jun. 24, 2011	Mar. 25, 2011
Date Paid	Jul. 08, 2011	Apr. 08, 2011
Amount Per Share	$ 0.15	$ 0.15	$ 0.15	$ 0.30	$ 0.30
Amount Paid	$ 18,709	$ 18,700		$ 37,390	$ 37,322

XML



Derivative Instrument and Hedging Activities 3 (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Cash Flow Hedges [Abstract]
Change in fair value - increase in Accumulated other comprehensive loss, excluding tax expense effect of $6,891, $1,308, $7,757 and $3,614, respectively	$ 18,478	$ 3,253	$ 20,748	$ 8,989
Reclassification of unrealized loss from Accumulated other comprehensive loss - increase of Interest expense, excluding tax expense effect of $2,253, $2,250, $4,481 and $4,554, respectively	5,615	5,607	11,166	11,357
Commodity Contracts Gathering and Processing [Abstract]
Change in fair value - increase/(decrease) in Accumulated other comprehensive loss, excluding tax expense effect of $(194), $390, $365 and $(9,613), respectively	(538)	1,080	1,014	(26,674)
Reclassification of unreazlied gain from Accumulated other comprehensive loss - increase of Operating revenues, exluding tax expense effect of $1,678, $1,830, $3,310 and $2,272, respectively	4,655	5,077	9,184	6,304
Economic Hedges Distribution [Abstract]
Change in fair value - increase/(decrease) in Deferred natural gas purchases	(4,279)	(23,947)	(23,772)	(7,707)
Economic Hedges Gathering and Processing [Abstract]
Change in fair value of strategic hedges - (increase)/decrease in Opearating revenues	7,149	(21,597)	23,865	(14,672)
Change in fair value of other hedges - (increase)/decrease in Operating revenues	$ (18)	$ (375)	$ (217)	$ 186

XML



Earnings per Share

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Earnings per Share

4. Earnings per Share

Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, increased by common stock equivalents from stock options, restricted stock and SARs. A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table for the periods presented.

	Three Months Ended June 30,		Six Months Ended June 30,
	2011	2010	2011	2010
	(In thousands)
Weighted average shares outstanding - Basic	124,712	124,474	124,685	124,445
Dilutive effect of share-based compensation awards	1,163	770	1,052	757
Weighted average shares outstanding - Diluted	125,875	125,244	125,737	125,202

The table below includes information related to stock options and SARs that were outstanding but have been excluded from the computation of weighted-average stock options due to the exercise price exceeding the weighted-average market price of the Company's common shares.

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Options and SARs excluded		-		1,235		-		1,235
Exercise price ranges		N/A	$	24.06 - 28.48		N/A	$	24.06 - 28.48
Weighted-average market price	$	30.11	$	23.70	$	28.67	$	23.73

XML



Comprehensive Income (Loss) 2 Parentheticals (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Comprehensive Income Loss [Line Items]
Change in fair value of interest rate hedges tax	$ (6,891)	$ (1,308)	$ (7,757)	$ (3,614)
Reclassification of unrealized loss (gain) on interest rate hedges tax	2,253	2,250	4,481	4,554
Change in fair value of commodity hedges tax	194	(390)	(365)	9,613
Relcassification of unrealized (gain) loss on commodity hedges into earnings tax	(1,678)	(1,830)	(3,310)	(2,272)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings tax	568	551	1,142	1,102
Change in other comprehensive income (loss) from equity investments tax	$ 21	$ 22	$ 43	$ 44

XML



Benefits (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Schedule Of Net Benefit Costs Table [Text Block]

		Pension Benefits				Other Postretirement Benefits
		Three Months Ended June 30,				Three Months Ended June 30,
		2011		2010		2011		2010
			(In thousands)
Service cost		$	935	$	768	$	881	$	793
Interest cost			2,525		2,509		1,446		1,409
Expected return on plan assets			(2,647)		(2,337)		(1,450)		(1,269)
Prior service cost (credit)
	amortization		147		138		(453)		(411)
Actuarial loss (gain)
	amortization		1,984		1,996		(403)		(451)
			2,944		3,074		21		71
Regulatory adjustment (1)			191		52		666		666
Net periodic benefit cost		$	3,135	$	3,126	$	687	$	737
		Pension Benefits				Other Postretirement Benefits
		Six Months Ended June 30,				Six Months Ended June 30,
		2011		2010		2011		2010
			(In thousands)
Service cost		$	1,870	$	1,535	$	1,761	$	1,586
Interest cost			5,050		5,019		2,892		2,819
Expected return on plan assets			(5,293)		(4,674)		(2,899)		(2,311)
Prior service cost (credit)
	amortization		294		276		(906)		(823)
Actuarial loss (gain)
	amortization		3,967		3,993		(806)		(901)
			5,888		6,149		42		370
Regulatory adjustment (1)			383		157		1,332		1,332
Net periodic benefit cost		$	6,271	$	6,306	$	1,374	$	1,702

________________________________

• 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.

XML



Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Schedule Of Segment Reporting Information By Segment Text Block

				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2011		2010		2011		2010
				(In thousands)
Operating revenues from external customers:
	Transportation and Storage			$	189,760	$	187,090	$	392,054	$	373,765
	Gathering and Processing				328,515		282,707		552,167		543,567
	Distribution				109,076		99,711		425,649		407,972
		Total segment operating revenues			627,351		569,508		1,369,870		1,325,304
	Corporate and other activities				4,256		3,588		8,559		6,786
				$	631,607	$	573,096	$	1,378,429	$	1,332,090
Depreciation and amortization:
	Transportation and Storage			$	31,963	$	30,896	$	64,237	$	60,073
	Gathering and Processing				18,065		17,971		35,852		35,291
	Distribution				8,407		7,967		16,814		15,923
		Total segment depreciation and amortization			58,435		56,834		116,903		111,287
	Corporate and other activities				860		725		1,719		1,466
				$	59,295	$	57,559	$	118,622	$	112,753
Earnings from unconsolidated investments:
	Transportation and Storage			$	24,852	$	25,748	$	50,883	$	42,994
	Gathering and Processing				(158)		1,395		30		2,380
	Corporate and other activities				354		399		836		746
				$	25,048	$	27,542	$	51,749	$	46,120
Segment performance:
	Transportation and Storage EBIT			$	117,495	$	111,246	$	239,593	$	213,671
	Gathering and Processing EBIT				21,333		40,526		9,104		47,081
	Distribution EBIT				3,374		6,865		26,941		35,710
		Total segment EBIT			142,202		158,637		275,638		296,462
	Corporate and other activities				(1,908)		297		(469)		617
	Interest expense				54,933		55,436		110,504		106,312
	Federal and state income taxes				25,588		28,609		44,230		59,418
	Net earnings				59,773		74,889		120,435		131,349
	Preferred stock dividends				-		2,170		-		4,341
	Loss on extinguishment of preferred stock				-		3,295		-		3,295
		Net earnings available for common
			stockholders	$	59,773	$	69,424	$	120,435	$	123,713
				June 30,		December 31,
				2011		2010
				(In thousands)
Total assets:
	Transportation and Storage			$	5,281,414	$	5,224,992
	Gathering and Processing				1,740,188		1,700,598
	Distribution				989,680		1,135,352
		Total segment assets			8,011,282		8,060,942
	Corporate and other activities				178,787		177,601
	Total assets			$	8,190,069	$	8,238,543
				Three Months Ended				Six Months Ended
				June 30,				June 30,
				2011		2010		2011		2010
				(In thousands)
Expenditures for long-lived assets:
	Transportation and Storage			$	28,911	$	25,886	$	39,169	$	56,257
	Gathering and Processing				20,903		15,823		56,513		41,706
	Distribution				13,447		9,151		20,409		16,255
		Total segment expenditures for long-lived
			assets		63,261		50,860		116,091		114,218
	Corporate and other activities				1,321		4,166		1,904		6,281
		Total expenditures for long-lived assets (1)		$	64,582	$	55,026	$	117,995	$	120,499

_______________________

• Related cash impact includes the net reduction in capital accruals totaling $10.4million and $7.9million for the three-month periods ended June 30, 2011 and 2010, respectively. Related cash impact includes the net reduction in capital accruals totaling $26 million and $(7.9)million for the six-month periods ended June 30, 2011 and 2010, respectively.

XML



Comprehensive Income (Loss) 1 (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Comprehensive Income Loss [Line Items]
Net Income (Loss) Attributable to Parent	$ 59,773	$ 74,889	$ 120,435	$ 131,349
Changes in other comprehensive income (loss):
Change in fair value of interest rate hedges net of tax of $(6,891), $(1,308), $(7,757) and $(3,614), respectively	(11,587)	(1,945)	(12,991)	(5,375)
Reclassification of unrealized loss (gain) on interest rate hedges net of tax of $2,253, $2,250, $4,481 and $4,554, respectively	3,362	3,357	6,685	6,803
Change in fair value of commodity hedges net of tax of $194, $(390), $(365) and $9,613, respectively	344	(690)	(649)	17,061
Relcassification of unrealized (gain) loss on commodity hedges into earnings net of tax of $(1,678), $(1,830), $(3,310) and $(2,272), respectively	(2,977)	(3,247)	(5,874)	(4,032)
Reclassification of net actuarial loss and prior service credit relating to pension and other postretirement benefits into earnings net of tax of $568, $551, $1,142 and $1,102, respectively	706	722	1,407	1,442
Change in other comprehensive income (loss) from equity investments net of tax of $21, $22, $43 and $44, respectively	37	35	72	71
Total other comprehensive income (loss)	(10,115)	(1,768)	(11,350)	15,970
Total comprehensive income	$ 49,658	$ 73,121	$ 109,085	$ 147,319

XML



Derivative Instrument and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Text Block

			Asset Derivatives (1)					Liability Derivatives (1)
			June 30,		December 31,		June 30,		December 31,
Balance Sheet Location			2011		2010		2011		2010
			(In thousands)				(In thousands)
Cash Flow Hedges:
Interest rate contracts
		Derivative instruments-liabilities	$	-	$	-	$	23,353	$	19,694
		Deferred credits		-		-		11,039		4,652
Commodity contracts - Gathering and Processing:
	Natural gas price swaps
		Derivative instruments-liabilities	$	9,275	$	16,459	$	-	$	-
		Deferred credits		230		-		-		-
	NGL price swaps
		Derivative instruments-liabilities		-		-		2,408		-
		Deferred credits		-		-		836		-
			$	9,505	$	16,459	$	37,636	$	24,346
Economic Hedges:
Commodity contracts - Gathering and Processing:
	NGL processing spread swaps
		Derivative instruments-liabilities	$	-	$	-	$	26,716	$	29,057
	Other derivative instruments
		Prepayments and other assets		9		133		-		-
Commodity contracts - Distribution:
	Natural gas price swaps
		Derivative instruments-liabilities	$	100	$	234	$	13,098	$	34,968
		Deferred credits		51		105		716		2,806
			$	160	$	472	$	40,530	$	66,831
	Total		$	9,665	$	16,931	$	78,166	$	91,177

_____________

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

Derivatives Effect On Income Table [Text Block]

				Three Months Ended June 30,				Six Months Ended June 30,
				2011		2010		2011		2010
				(In thousands)
Cash Flow Hedges: (1)
	Interest rate contracts:
		Change in fair value - increase in Accumulated other comprehensive
			loss, excluding tax expense effect of $6,891, $1,308, $7,757 and $3,614, respectively	$	18,478	$	3,253	$	20,748	$	8,989
		Reclassification of unrealized loss from Accumulated other
			comprehensive loss - increase of Interest expense, excluding tax
			expense effect of $2,253, $2,250, $4,481 and $4,554 respectively		5,615		5,607		11,166		11,357
	Commodity contracts - Gathering and Processing:
		Change in fair value - increase/(decrease) in Accumulated other
			comprehensiveloss, excluding tax expense effect of $(194), $390, $365 and $(9,613), respectively		(538)		1,080		1,014		(26,674)
		Reclassification of unrealized gain from Accumulated other
			comprehensiveloss - increase of Operating revenues, excluding
			tax expense effect of $1,678, $1,830, $3,310 and $2,272, respectively		4,655		5,077		9,184		6,304
Economic Hedges:
	Commodity contracts - Gathering and Processing:
		Change in fair value of strategic hedges - (increase)/decrease in Operating revenues (2)			7,149		(21,597)		23,865		(14,672)
		Change in fair value of other hedges - (increase)/decrease in Operating revenues			(18)		(375)		(217)		186
	Commodity contracts - Distribution:
		Change in fair value - decrease in Deferred natural gas purchases			(4,279)		(23,947)		(23,772)		(7,707)

_________________

• See Note 6 – Comprehensive Income (Loss) for additional related information.
• Includes $7.3million and $16.8million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2011, respectively. Includes $9 million and $20 million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2010, respectively. Additionally, includes a $300,000 unrealized mark-to-market gain and a $14.4 million unrealized mark-to-market loss recorded in the three-month and six-month periods ended June 30, 2011, respectively, and $22.3 million and $16.6 million of unrealized mark-to-market gains recorded in the three-month and six-month periods ended June 30, 2010, respectively.

XML



Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Commitments and Contingencies

12. 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 applicable environmental laws, rules and regulations may expose the Company to significant fines, penalties and/or interruptions in operations. The Company's environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

Environmental Remediation

Transportation and Storage Segment

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

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

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

Gathering and Processing Segment

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

Distribution Segment

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

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

North Attleboro MGP Site in Massachusetts (North Attleboro Site). In November 2003, the MADEP issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the North Attleboro Site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. Assessment activities have recently been completed and it is estimated that the Company will spend approximately $10.6million 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 Sheet.

Environmental Remediation Liabilities

The table below reflects the amount of accrued liabilities recorded in the Condensed Consolidated Balance Sheet at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable. The Company does not have any material environmental remediation matters assessed as reasonably possible.

	June 30,		December 31,
	2011		2010
	(In thousands)
Current	$	5,890	$	10,648
Noncurrent		15,517		11,920
Total environmental liabilities	$	21,407	$	22,568

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 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 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.

East End Project. The East End project involved the installation of a total of approximately 31 miles of pipeline in and around Tuscola, Illinois, Montezuma, Indiana and Zionsville, Indiana.  Construction began in 2007 and was completed in the second quarter of 2008.  PEPL sought recovery of each contractor's share of approximately $50 million of cost overruns from the construction contractor, an inspection contractor and the construction management contractor for improper welding, inspection and construction management of the East End Project.  Certain of the contractors filed counterclaims against PEPL for alleged underpayments of approximately $18 million.  Panhandle settled with three defendants prior to trial in Harris County, Texas. Trial began on May 16, 2011 and after the fourth week of trial a settlement was reached with the last defendant, Acuren.  The various settlements resulted in the Company receiving a total of approximately $16 million and $9 million for reimbursement of previously incurred legal expenses associated with the proceeding and project cost overruns, respectively.

Attorney General of the Commonwealth of Massachusetts Attorney General 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 current 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 legal fees charged that were passed through the recovery mechanism and whether they would qualify for a lesser, 50 percent, level of recovery.The Company believes it has complied with all applicable requirements of the MDPU regarding its filings for cost recovery; 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. In March, the NMED amended the consent order it filed against SUGS in 2010, removing numerous claims and adding several more.

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 333rd Judicial District Court of Harris County, Texas. The petition names as defendants the members of Southern Union's Board, as well as Southern Union and ETE. The plaintiff alleges 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 alleges 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 seeks injunctive relief, including to enjoin 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 11th Judicial District Court of Harris County, Texas.  The petition named as defendants the members of Southern Union's Board, Southern Union, and ETE.  The plaintiff alleges 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 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, and that defendants have failed to disclose all material information related to the merger to Southern Union stockholders. The petition seeks injunctive relief, including to enjoin the merger, and an award of attorneys' and other fees and costs, in addition to other relief.  On June 28, 2011, an amended petition was filed, 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 those alleged breaches of fiduciary duty.  The amended petition 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 defendants have failed to disclose all material information related to the merger to Southern Union stockholders.  The amended petition seeks injunctive relief, including to enjoin the merger, and an award of attorneys' and other fees and costs, in addition to other relief.

The plaintiffs in the two Texas cases filed a motion to appoint lead counsel and a motion for expedited discovery. To date, no preliminary injunctions have been filed in these Texas cases.

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 names as defendants the members of Southern Union's Board, Southern Union, and ETE. The plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union's stockholders in connection with the merger, and further claim that ETE aided and abetted those alleged breaches. The 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 directors should deem a competing proposal made by The Williams Companies, Inc. (Williams) to be superior. The complaint seeks compensatory damages, injunctive relief, including to enjoin 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 name as defendants the members of Southern Union's Board, Southern Union, ETE, and Merger Sub. The plaintiffs allege 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 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 the directors must give full consideration to the Williams proposal. The complaint seeks compensatory damages, injunctive relief, including to enjoin 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 names as defendants the members of Southern Union's Board, Southern Union, ETE, and Merger Sub. The plaintiffs allege 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 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, and that the terms of the amended merger agreement are preclusive. The complaint seeks injunctive relief, including to enjoin the merger, and an award of attorneys' and other fees and costs, in addition to other relief.

To date, the four Delaware plaintiffs have filed no preliminary injunctions or motions to appoint lead counsel or consolidate the lawsuits.  The Company believes the allegations of all the foregoing actions lack merit and will contest them.

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 establishes reserves for litigation and other claim costs when management believes a loss is probable and reasonably estimable. As of June 30, 2011 and December 31, 2010, the Company recorded litigation and other claim-related accrued liabilities of $28.2 million and $26.9 million, respectively. Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as reasonably possible.

Other Commitments and Contingencies

Regulation and Rates.See Note 14 – Regulation and Rates for potential contingent matters associated with the Company's regulated operations.

Future Regulatory Compliance Commitments

SPCC Rules. In 2008 and 2009, the EPA adopted amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements and streamlining requirements. On October 7, 2010, EPA amended the compliance date for certain facilities from November 10, 2010 to November 10, 2011. The Company is currently reviewing the impact of the modified regulations on its operations in its Transportation and Storage and Gathering and Processing segments and may incur costs for tank integrity testing, alarms and other associated corrective actions as well as potential upgrades to containment structures. Costs associated with such activities cannot be estimated with 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.

Air Quality Control

Transportation and Storage Segment. In August 2010, 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. EPA lowered the ozone standard to seventy-five parts per billion (ppb) in 2008 with compliance anticipated in 2013 to 2015. In January 2010, 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 January 2010, 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, proposed revisions to the 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 Kansas Department of Health and Environment set certain contingency measures as part of the agency's ozone maintenance plan for the Kansas City area. These measures must be revised to conform to the requirements of the EPA ozone standard discussed above. As such, the 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 proposed plan, such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 New Mexico will address the sulfur dioxide standard.

XML



Reportable Segments 1 (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Segment Reporting Information Line Items
Operating revenues from external customers	$ 631,607	$ 573,096	$ 1,378,429	$ 1,332,090
Depreciation and amortization	59,295	57,559	118,622	112,753
Earnings from unconsolidated investments	25,048	27,542	51,749	46,120
Interest expense	54,933	55,436	110,504	106,312
Federal and state income tax expense	25,588	28,609	44,230	59,418
Net earnings	59,773	74,889	120,435	131,349
Preferred stock dividends	0	2,170	0	4,341
Loss on extinguishment of preferred stock	0	3,295	0	3,295
Net earnings available for common stockholders	59,773	69,424	120,435	123,713
Assets	8,190,069		8,190,069		8,238,543
Expenditures for long-lived assets	64,582	55,026	117,995	120,499
Transportation And Storage [Member]
Segment Reporting Information Line Items
Operating revenues from external customers	189,760	187,090	392,054	373,765
Depreciation and amortization	31,963	30,896	64,237	60,073
Earnings from unconsolidated investments	24,852	25,748	50,883	42,994
EBIT	117,495	111,246	239,593	213,671
Assets	5,281,414		5,281,414		5,224,992
Expenditures for long-lived assets	28,911	25,886	39,169	56,257
Gathering And Processing [Member]
Segment Reporting Information Line Items
Operating revenues from external customers	328,515	282,707	552,167	543,567
Depreciation and amortization	18,065	17,971	35,852	35,291
Earnings from unconsolidated investments	(158)	1,395	30	2,380
EBIT	21,333	40,526	9,104	47,081
Assets	1,740,188		1,740,188		1,700,598
Expenditures for long-lived assets	20,903	15,823	56,513	41,706
Distribution [Member]
Segment Reporting Information Line Items
Operating revenues from external customers	109,076	99,711	425,649	407,972
Depreciation and amortization	8,407	7,967	16,814	15,923
EBIT	3,374	6,865	26,941	35,710
Assets	989,680		989,680		1,135,352
Expenditures for long-lived assets	13,447	9,151	20,409	16,255
Total Segment [Member]
Segment Reporting Information Line Items
Operating revenues from external customers	627,351	569,508	1,369,870	1,325,304
Depreciation and amortization	58,435	56,834	116,903	111,287
EBIT	142,202	158,637	275,638	296,462
Assets	8,011,282		8,011,282		8,060,942
Expenditures for long-lived assets	63,261	50,860	116,091	114,218
Corporate And Other Activities [Member]
Segment Reporting Information Line Items
Operating revenues from external customers	4,256	3,588	8,559	6,786
Depreciation and amortization	860	725	1,719	1,466
Earnings from unconsolidated investments	354	399	836	746
EBIT	(1,908)	297	(469)	617
Assets	178,787		178,787		177,601
Expenditures for long-lived assets	$ 1,321	$ 4,166	$ 1,904	$ 6,281

XML



Unconsolidated Investments

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Unconsolidated Investments

5. Unconsolidated Investments

Unconsolidated investments at June 30, 2011 and December 31, 2010 include the Company's 50 percent investment in Citrus and investments in other entities. The Company accounts for these investments using the equity method. The Company's share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the unaudited interim Condensed Consolidated Statement of Operations.

The following table summarizes the Company's unconsolidated equity investments at the dates indicated.

	June 30,		December 31,
	2011		2010
		(In thousands)
Citrus (1)	$	1,561,664	$	1,510,847
Other		26,199		27,701
	$	1,587,863	$	1,538,548

___________________

(1) See Note 3 – ETE Merger for information regarding the Company's intent for its ownership interest in Citrus to be merged with an ETP subsidiary.

The following table sets forth summarized financial information for the Company's equity investments for the periods presented.

	Three Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	194,361	$	2,506	$	140,572	$	5,823
Operating income		118,716		705		77,323		3,297
Net earnings		47,173		689		46,460		3,101
	Six Months Ended June 30,
	2011				2010
			Other Equity				Other Equity
	Citrus		Investments		Citrus		Investments
	(In thousands)
Statement of Operations Data:
Revenues	$	308,246	$	5,082	$	254,711	$	11,684
Operating income		168,598		1,637		129,694		6,482
Net earnings		96,526		1,844		76,087		6,270

Citrus Dividends. Citrus did not pay dividends to the Company during the three-month periods ended and six-month periods endedJune 30, 2011 and 2010.

Contingent Matters Potentially Impacting Southern Union Through the Company's Investment in Citrus

Florida Gas Phase VIII Expansion.  Florida Gas' Phase VIII Expansion project was placed in-service on April1, 2011, at an estimated cost of approximately $2.48 billion, including capitalized equity and debt costs. To date, Florida Gas has entered into firm transportation service agreements with shippers for 25-year terms accounting for approximately 74 percent of the available expansion capacity.

In 2011, the Company, through an indirect wholly-owned subsidiary, and Citrus' other shareholder each made sponsor contributions of $72 million in the form of loans to Citrus.   The Company has recorded the Citrus loan in Other non-current assets on the Condensed Consolidated Balance Sheet. The contributions are related to the costs of Florida Gas' Phase VIII Expansion project.  In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each shareholder 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 aone-month Eurodollar rate plus a credit spread of 1.5percent. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs.  Citrus' principal operating asset is Florida Gas, whose debt is rated Baa2 by Moody's Investor Services, Inc. and BBB by Standard & Poors.

Florida Gas 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 Florida Gas' 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 Florida Gas $82.7 million and rejected all damage claims by the FDOT/FTE.On May 2, 2011, the judge issued an order entitling Florida Gas to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that Florida Gasis 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 Florida Gas' pipelinewithout the consent of Florida Gas although Florida Gas would be required to relocate the pipeline if it did not provide such consent. He also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. Amounts ultimately received would primarily reduce Florida Gas' property, plant and equipment costs.

On April 14, 2011 Florida Gas filed suit against the FDOT/FTE, Dragados USA and I-595 Express, LLC in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in Florida Gas easements containing the newly constructed 36-inch pipeline.  The same judge that presided over the previously discussed FDOT/FTE proceeding was assigned to the case.  Trial is expected to be set in early 2012.

XML



Stockholders' Equity

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Stockholders' Equity

15. Stockholders' Equity

Dividends. The table below presents the amount of cash dividends declared and paid in the period.

Shareholder	Date	Amount		Amount
Record Date	Paid	Per Share		Paid
				(In thousands)
June 24, 2011	July 8, 2011	$	0.15	$	18,709
March 25, 2011	April 8, 2011		0.15		18,700

XML



Unconsolidated Investments 2 (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Citrus [Member]
Statement of Operations Data:
Revenues	$ 194,361	$ 140,572	$ 308,246	$ 254,711
Operating income	118,716	77,323	168,598	129,694
Net earnings	47,173	46,460	96,526	76,087
Other Unconsolidated Investments [Member]
Statement of Operations Data:
Revenues	2,506	5,823	5,082	11,684
Operating income	705	3,297	1,637	6,482
Net earnings	$ 689	$ 3,101	$ 1,844	$ 6,270

XML



Taxes on Income (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Income Tax Table [Text Block]

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In thousands)
Income tax expense	$	25,588		$	28,609		$	44,230		$	59,418
Effective tax rate		30	%		28	%		27	%		31	%

XML



CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows provided by (used in) operating activities:
Net earnings	$ 120,435,000	$ 131,349,000
Adjustments to reconcile net earnings to net cash flows provided by (used in) operating activities:
Depreciation and amortization	118,622,000	112,753,000
Deferred income taxes	51,543,000	60,087,000
Provision for bad debts	9,864,000	9,562,000
Unrealized (gain) loss on commodity derivatives	14,413,000	(16,654,000)
Share-based compensation expense	4,899,000	4,454,000
Earnings from unconsolidated investments	(50,249,000)	(42,396,000)
Changes in operating assets and liabilities	81,384,000	(16,663,000)
Net cash flows provided by operating activities	350,911,000	242,492,000
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment	(143,902,000)	(129,379,000)
Loan to unconsolidated investments	(72,000,000)	0
Plant retirements and other	(488,000)	359,000
Net cash flows used in investing activities	(216,390,000)	(129,020,000)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft	4,877,000	(12,030,000)
Issuance of long-term debt	0	857,000
Renewal cost for credit facilities	(2,138,000)	(5,831,000)
Dividends paid on common stock	(37,390,000)	(37,322,000)
Dividends paid on preferred stock	0	(4,341,000)
Repayment of long-term debt obligation	(278,000)	(140,723,000)
Net change in revolving credit facilities	(101,572,000)	76,095,000
Other	1,694,000	1,866,000
Net cash flows provided by (used in) financing activities	(134,807,000)	(121,429,000)
Change in cash and cash equivalents	(286,000)	(7,957,000)
Cash and cash equivalents at beginning of period	3,299,000	10,545,000
Cash and cash equivalents at end of period	$ 3,013,000	$ 2,588,000

XML



Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Earnings Per Share, Policy [Policy Text Block]

Basic earnings per share is computed based on the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed based on the weighted average number of common shares outstanding during each period, increased by common stock equivalents from stock options, restricted stock and SARs. A reconciliation of the shares used in the basic and diluted earnings per share calculations is shown in the following table for the periods presented.

Equity Method Investments, Policy [Policy Text Block]

Unconsolidated investments at June 30, 2011 and December 31, 2010 include the Company's 50 percent investment in Citrus and investments in other entities. The Company accounts for these investments using the equity method. The Company's share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the unaudited interim Condensed Consolidated Statement of Operations.

Derivatives, Policy [Policy Text Block]

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.

The interest rate swaps will effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notesand are accounted foras cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

Any ineffective portion of the cash flow hedge is reported in current-period earnings.

These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

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

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

Fair Value of Financial Instruments, Policy [Policy Text Block]

The Company's Level 1 instruments primarily consist of trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes. 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, 2011 or December 31, 2010.

Commitments and Contingencies, Policy [Policy Text Block]

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 applicable 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.

The table below reflects the amount of accrued liabilities recorded in the Condensed Consolidated Balance Sheet at the dates indicated to cover environmental remediation actions where management believes a loss is probable and reasonably estimable. The Company does not have any material environmental remediation matters assessed as reasonably possible.

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 establishes reserves for litigation and other claim costs when management believes a loss is probable and reasonably estimable. As of June 30, 2011 and December 31, 2010, the Company recorded litigation and other claim-related accrued liabilities of $28.2 million and $26.9 million, respectively. Except for the matters discussed above, the Company does not have any material litigation or other claim contingency matters assessed as reasonably possible.

Segment Reporting, Policy [Policy Text Block]

The Company's 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.

XML



Debt Obligations 1 (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Debt Instrument Line Items
Total Long Term Debt Carrying Value	$ 3,521,806	$ 3,521,989
Long Term Debt Fair Value	3,822,328	3,689,892
Credit Facilities	195,479	297,051
Credit Facilities Fair Value	195,487	301,312
Total consolidated debt obligations	3,717,285	3,819,040
Total consolidated debt obligations fair value	4,017,815	3,991,204
Less current portion of long-term debt	816,272	1,083
Less short-term debt	195,479	297,051
Total long-term debt	2,705,534	3,520,906
Senior Notes due 2024 [Member] | Southern Union [Member]
Debt Instrument Line Items
Interest Rate	7.60%	7.60%
Total Long Term Debt Carrying Value	359,765	359,765
Long Term Debt Fair Value	428,300	392,144
Senior Notes Due 2029 [Member] | Southern Union [Member]
Debt Instrument Line Items
Interest Rate	8.25%	8.25%
Total Long Term Debt Carrying Value	300,000	300,000
Long Term Debt Fair Value	377,403	332,922
Senior Notes Due 2029 [Member] | Panhandle [Member]
Debt Instrument Line Items
Interest Rate	7.00%	7.00%
Total Long Term Debt Carrying Value	66,305	66,305
Long Term Debt Fair Value	70,068	69,911
First Mortgage Bonds due 2020 to 2027 [Member] | Southern Union [Member]
Debt Instrument Line Items
Interest Rate Minimum	7.24%	7.24%
Interest Rate Maximum	9.44%	9.44%
Total Long Term Debt Carrying Value	19,500	19,500
Long Term Debt Fair Value	23,558	21,473
Junior Subordinated Notes due 2066 [Member] | Southern Union [Member]
Debt Instrument Line Items
Interest Rate	7.20%	7.20%
Total Long Term Debt Carrying Value	600,000	600,000
Long Term Debt Fair Value	575,280	609,743
Term Loan 2013 [Member] | Southern Union [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	250,000	250,000
Long Term Debt Fair Value	252,491	249,915
Note Payable [Member] | Southern Union [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	8,019	8,297
Long Term Debt Fair Value	8,019	8,297
Senior Notes due 2013 [Member] | Panhandle [Member]
Debt Instrument Line Items
Interest Rate	6.05%	6.05%
Total Long Term Debt Carrying Value	250,000	250,000
Long Term Debt Fair Value	273,260	268,988
Senior Notes due 2017 [Member] | Panhandle [Member]
Debt Instrument Line Items
Interest Rate	6.20%	6.20%
Total Long Term Debt Carrying Value	300,000	300,000
Long Term Debt Fair Value	346,413	322,893
Senior Notes due 2019 [Member] | Panhandle [Member]
Debt Instrument Line Items
Interest Rate	8.125%	8.125%
Total Long Term Debt Carrying Value	150,000	150,000
Long Term Debt Fair Value	183,813	169,671
Senior Notes due 2018 [Member] | Panhandle [Member]
Debt Instrument Line Items
Interest Rate	7.00%	7.00%
Total Long Term Debt Carrying Value	400,000	400,000
Long Term Debt Fair Value	472,416	442,120
Term Loan 2012 [Member] | Panhandle [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	815,391	815,391
Long Term Debt Fair Value	808,481	799,084
Net Premiums [Member] | Panhandle [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	2,826	2,731
Long Term Debt Fair Value	2,826	2,731
Southern Union [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	1,537,284	1,537,562
Long Term Debt Fair Value	1,665,051	1,614,494
Panhandle [Member]
Debt Instrument Line Items
Total Long Term Debt Carrying Value	1,984,522	1,984,427
Long Term Debt Fair Value	$ 2,157,277	$ 2,075,398

XML



Earnings per Share (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Schedule Of Weighted Average Number Of Shares Table [Text Block]

	Three Months Ended June 30,		Six Months Ended June 30,
	2011	2010	2011	2010
	(In thousands)
Weighted average shares outstanding - Basic	124,712	124,474	124,685	124,445
Dilutive effect of share-based compensation awards	1,163	770	1,052	757
Weighted average shares outstanding - Diluted	125,875	125,244	125,737	125,202

Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share Text Block

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Options and SARs excluded		-		1,235		-		1,235
Exercise price ranges		N/A	$	24.06 - 28.48		N/A	$	24.06 - 28.48
Weighted-average market price	$	30.11	$	23.70	$	28.67	$	23.73

XML



Description of Business

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Description of Business

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, 2010, 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 balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Due to the seasonal nature of the Company's operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year.

1. Description of Business

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, treating, processing, transportation, storage and distribution of natural gas in the United States. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution. 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 also provides LNG terminalling and regasification services. 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. 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 intent to merge with ETE.

XML



Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Derivative Instruments and Hedging Activities

10. 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.

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 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 will become effective on November 1, 2011. The Company will pay interest on the Junior Subordinated Notes at the floating rate of three-month LIBOR plus a credit spread of 3.0175 percent beginning November 1, 2011. The interest rate swaps will effectively fix the interest rate applicable to the floating rate on a portion of the Junior Subordinated Notesand are accounted foras cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.There was no swap ineffectivenessduring the period ended June 30, 2011.  As of June 30, 2011, the floating rate LIBOR-based portion of the interest payments commencing November 1, 2011 was exchanged for weighted average fixed rate interest payments of 3.63 percent.

The Company also has outstanding pay-fixed interest rate swaps with a total notional amount of $455 million applicable to the LNG Holdings $455 million term loan. These interest rate swaps are accounted for as cash flow hedges, with the effective portion of changes in their fair value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

As of June 30, 2011, approximately $14.2million of net after-tax gains in Accumulated other comprehensive loss related to these interest rate swaps is expected to be amortized into Interest expense during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

Treasury Rate Locks. As of June 30, 2011, the Company had no outstanding treasury rate locks. However, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in Accumulated other comprehensive loss and reclassified into Interest expense in the same periods during which the related interest payments on long-term debt impact earnings. As of June 30, 2011, approximately $571,000 of net after-tax losses in Accumulated other comprehensive loss related to these treasury rate locks will be amortized into Interest expense during the next twelve months.

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

Natural Gas Price Swaps. As of June 30, 2011, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 8,280,000 MMBtu for the remainder of 2011 and 3,660,000MMBtu for 2012. 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 loss and reclassified into Operating revenues in the same periods during which the forecasted natural gas sales impact earnings. As of June 30, 2011, approximately $6 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps are expected to be amortized into 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, 2011, the Company had outstanding receive-fixed NGL price swaps with a total notional amount of 65,378,124gallons (5,490,000MMBtu equivalent basis) for 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 loss and reclassified into Operating revenues in the same periods during which the forecasted NGL sales impact earnings. As of June 30, 2011, approximately $1.6million of net after-tax losses in Accumulated other comprehensive loss related to these NGL price swaps are expected to be amortized into Operating revenues during the next twelve months. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Processing Spread Swaps. As of June 30, 2011, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 4,600,000 MMBtu equivalents for the remainder of 2011. These processing spread swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues.

Commodity Contracts - Distribution Segment

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

Natural Gas Price Swaps. As of June 30, 2011, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 8,490,000MMBtu,14,270,000 MMBtu and 2,020,000MMBtu for the remainder of 2011,2012 and 2013, 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 derivative instruments and their location in the unaudited interim Condensed Consolidated Balance Sheet at the dates indicated.

			Asset Derivatives (1)					Liability Derivatives (1)
			June 30,		December 31,		June 30,		December 31,
Balance Sheet Location			2011		2010		2011		2010
			(In thousands)				(In thousands)
Cash Flow Hedges:
Interest rate contracts
		Derivative instruments-liabilities	$	-	$	-	$	23,353	$	19,694
		Deferred credits		-		-		11,039		4,652
Commodity contracts - Gathering and Processing:
	Natural gas price swaps
		Derivative instruments-liabilities	$	9,275	$	16,459	$	-	$	-
		Deferred credits		230		-		-		-
	NGL price swaps
		Derivative instruments-liabilities		-		-		2,408		-
		Deferred credits		-		-		836		-
			$	9,505	$	16,459	$	37,636	$	24,346
Economic Hedges:
Commodity contracts - Gathering and Processing:
	NGL processing spread swaps
		Derivative instruments-liabilities	$	-	$	-	$	26,716	$	29,057
	Other derivative instruments
		Prepayments and other assets		9		133		-		-
Commodity contracts - Distribution:
	Natural gas price swaps
		Derivative instruments-liabilities	$	100	$	234	$	13,098	$	34,968
		Deferred credits		51		105		716		2,806
			$	160	$	472	$	40,530	$	66,831
	Total		$	9,665	$	16,931	$	78,166	$	91,177

_____________

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

The following table summarizes the location and amount of derivative instrument gains and losses reported in the Company's unaudited interim condensed consolidated financial statements for the periods presented.

				Three Months Ended June 30,				Six Months Ended June 30,
				2011		2010		2011		2010
				(In thousands)
Cash Flow Hedges: (1)
	Interest rate contracts:
		Change in fair value - increase in Accumulated other comprehensive
			loss, excluding tax expense effect of $6,891, $1,308, $7,757 and $3,614, respectively	$	18,478	$	3,253	$	20,748	$	8,989
		Reclassification of unrealized loss from Accumulated other
			comprehensive loss - increase of Interest expense, excluding tax
			expense effect of $2,253, $2,250, $4,481 and $4,554 respectively		5,615		5,607		11,166		11,357
	Commodity contracts - Gathering and Processing:
		Change in fair value - increase/(decrease) in Accumulated other
			comprehensiveloss, excluding tax expense effect of $(194), $390, $365 and $(9,613), respectively		(538)		1,080		1,014		(26,674)
		Reclassification of unrealized gain from Accumulated other
			comprehensiveloss - increase of Operating revenues, excluding
			tax expense effect of $1,678, $1,830, $3,310 and $2,272, respectively		4,655		5,077		9,184		6,304
Economic Hedges:
	Commodity contracts - Gathering and Processing:
		Change in fair value of strategic hedges - (increase)/decrease in Operating revenues (2)			7,149		(21,597)		23,865		(14,672)
		Change in fair value of other hedges - (increase)/decrease in Operating revenues			(18)		(375)		(217)		186
	Commodity contracts - Distribution:
		Change in fair value - decrease in Deferred natural gas purchases			(4,279)		(23,947)		(23,772)		(7,707)

_________________

• See Note 6 – Comprehensive Income (Loss) for additional related information.
• Includes $7.3million and $16.8million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2011, respectively. Includes $9 million and $20 million of the cash settlement impact for previously recognized unrealized losses in the three-month and six-month periods ended June 30, 2010, respectively. Additionally, includes a $300,000 unrealized mark-to-market gain and a $14.4 million unrealized mark-to-market loss recorded in the three-month and six-month periods ended June 30, 2011, respectively, and $22.3 million and $16.6 million of unrealized mark-to-market gains recorded in the three-month and six-month periods ended June 30, 2010, respectively.

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, 2011 was $8 million

XML



Commitments and Contingencies 2 Narrative (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Commitments And Contingencies [Abstract]
Site Contingency Loss Exposure Not Accrued Best Estimate	$ 10.6
Legal Fees	18.5
Percentage Of Recovery	50
Estimated Litigation Liability	28.2	26.9
Recovery Units	three
East End Project [Member]
Commitments And Contingencies [Abstract]
Pipelines Installed	31
Cost Overruns Recovery	50
Alleged Underpayments	18
Proceeds From Legal Settlements	16.0
Reimbursement Cost Overruns	$ 9

XML



Regulation and Rates (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended			0 Months Ended		1 Months Ended	0 Months Ended				3 Months Ended
	Dec. 13, 2010 Panhandle [Member]	Mar. 01, 2011 Panhandle [Member]	Aug. 31, 2009 Panhandle [Member]	Feb. 10, 2010 Missouri Gas Energy [Member]	Apr. 02, 2009 Missouri Gas Energy [Member]	Feb. 28, 2010 Missouri Gas Energy [Member]	Jul. 13, 2011 New England Gas Company [Member]	Sep. 16, 2010 New England Gas Company [Member]	Nov. 13, 2009 New England Gas Company [Member]	Sep. 15, 2008 New England Gas Company [Member]	Mar. 31, 2011 New England Gas Company [Member]
Regulated Operations [Abstract]
Amount Of Regulatory Costs Not Yet Approved		$ 54	$ 38
Surcharge Recovery Period	21.4
Base Rate Increase					32.4			6.2
Revenue Increase Authorized				16.2
Percent Residential Small General Service Customers						99
Percent Residential Small General Service Net Operating Revenues						91
Base Rate Increase Authorized											5.1
Earnings Share Adjustment Recovery									1.7	4.0
Remand Recovery							$ 4.1

XML



Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Dividends Table [Text Block]

Shareholder	Date	Amount		Amount
Record Date	Paid	Per Share		Paid
				(In thousands)
June 24, 2011	July 8, 2011	$	0.15	$	18,709
March 25, 2011	April 8, 2011		0.15		18,700

XML



Regulation and Rates

6 Months Ended

Jun. 30, 2011

Notes to Financial Statements [Abstract]

Regulation and Rates

14. Regulation and Rates

Panhandle.On August 31, 2009, Sea Robin filed with FERC to implement a rate surcharge to recover Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, with initial accumulated net costs of approximately $38 million included in the filing.  On September 30, 2009, FERC approved the surcharge to be effective March 1, 2010, subject to refund and the outcome of hearings with FERC to explore issues set forth in certain customer protests, including the costs to be included and the applicability of the surcharge to discounted contracts.  The Administrative Law Judge issued an initial decision on December 13, 2010, approving the surcharge for recovery from all shippers, including discounted and non-discounted shippers, over a recovery period of 21.4 years and including applicable carrying charges. The Company, as well as other parties, have filed briefs for exception on certain aspects of the decision. On March 1, 2011, Sea Robin submitted its latest semiannual filing related to the surcharge, which reflected updated costs incurred through December 31, 2010 of approximately $54 million, net of insurance and surcharge recoveries, which were reflected in the updated surcharge rate effective April 1, 2011, subject to refund. The ultimate outcome of this matter is still pending a final FERC decision.

Missouri Gas Energy.On July 13, 2011, a joint application was filed by Southern Union, Sigma and ETE requesting that the MPSC authorize Southern Union to take certain actions to allow ETE to acquire the equity interests of Southern Union. Although no procedural schedule has been established, on July 14, 2011, the MPSC issued an order directing its staff to file, by August 15, 2011, its recommendation regarding the proposed merger, or a status report indicating when it will be able to file its recommendation. For additional related information, see Note 3 – ETE Merger.

On June 10, 2011, Missouri Gas Energy filed an application with the MPSC requesting authority to defer the financial impact of the tornado which struck Joplin, Missouri on May 22, 2011, on the grounds that the tornado constituted a material, extraordinary and non-recurring event with respect to Missouri Gas Energy's operations. If deferral authority is granted, Missouri Gas Energy would be permitted to defer as a regulatory asset for consideration of recovery in a future rate proceeding the incremental costs and lost fixed cost recovery occasioned by the tornado. It is expected that the MPSC will address this request within a reasonable, but presently unknown time frame, but in no event later than January 2012.

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 percent of its total customers and approximately 91 percent 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. Those judicial review proceedings are not expected to be complete until 2012, and the results of those judicial review proceedings are not expected to have a material adverse impact on the Company's consolidated financial position, results of operations or cash flows.

New England Gas Company.On September 16, 2010, New England Gas Company made a filing with the MDPU seeking to implement an annual base rate increase of approximately $6.2 million.  On March 31, 2011, the MDPU issued its order in this matter, awarding New England Gas Company a base rate increase of approximately $5.1 million and authorizing implementation of a revenue decoupling mechanism, which mitigates conservation and weather impacts, and implementation of a targeted infrastructure recovery factor, which permits recovery of revenue requirement (return, depreciation, property taxes and income taxes) associated with replacement of certain aged facilities without the necessity of filing and prosecuting a base rate increase. The new rate structure and rates became effective for gas sold on and after April 1, 2011.

On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50 percent of the amount by which its 2007 earnings fell below a return on equity of 7 percent. 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 percent 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 12-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 May 13, 2011, the independent auditor selected by the MDPU submitted the final audit report pertaining to 2007 cost of service information as ordered by the MDPU in connection with New England Gas Company's 2008 base rate proceeding. The Company does not expect further activity in the proceeding unless the MDPU orders further action in response to the final audit report submission.

XML



CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED) (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income Statement [Abstract]
Operating revenues	$ 631,607	$ 573,096	$ 1,378,429	$ 1,332,090
Operating expenses:
Cost of natural gas and other energy	315,575	246,626	741,207	685,635
Operating, maintenance and general	123,858	118,723	244,852	232,608
Depreciation and amortization	59,295	57,559	118,622	112,753
Revenue-related taxes	5,200	4,806	22,567	21,848
Taxes, other than on income and revenues	12,657	13,638	28,127	28,224
Total operating expenses	516,585	441,352	1,155,375	1,081,068
Operating income	115,022	131,744	223,054	251,022
Other income (expenses):
Interest expense	(54,933)	(55,436)	(110,504)	(106,312)
Earnings from unconsolidated investments	25,048	27,542	51,749	46,120
Other, net	224	(352)	366	(63)
Total other expenses, net	(29,661)	(28,246)	(58,389)	(60,255)
Earnings before income taxes	85,361	103,498	164,665	190,767
Federal and state income tax expense	25,588	28,609	44,230	59,418
Net earnings	59,773	74,889	120,435	131,349
Preferred stock dividends	0	(2,170)	0	(4,341)
Loss on extinguishment of preferred stock	0	(3,295)	0	(3,295)
Net earnings available for common stockholders	$ 59,773	$ 69,424	$ 120,435	$ 123,713
Net earnings available for common stockholders per share:
Basic	$ 0.48	$ 0.56	$ 0.97	$ 0.99
Diluted	$ 0.47	$ 0.55	$ 0.96	$ 0.99
Cash dividends declared on common stock per share:	$ 0.15	$ 0.15	$ 0.30	$ 0.30
Weighted average shares outstanding:
Basic	124,712	124,474	124,685	124,445
Diluted	125,875	125,244	125,737	125,202

XML



Earnings per Share 1 (Details) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Weighted Average Shares Outstanding [Line Items]
Weighted Average Shares Outstanding, Basic	124,712	124,474	124,685	124,445
Dilutive effect of share-based compensation awards	1,163	770	1,052	757
Weighted Average Shares Outstanding, Diluted	125,875	125,244	125,737	125,202

XML



Derivative Instrument and Hedging Activities 1 Narrative (Details) (USD $)		0 Months Ended	6 Months Ended				6 Months Ended						6 Months Ended
	Jun. 30, 2010	Nov. 01, 2011 Interest Rate Swaps [Member]	Jun. 30, 2011 Interest Rate Swaps [Member]	Jun. 30, 2011 Interest Rate Swaps [Member] Ten Year [Member]	Jun. 30, 2011 Interest Rate Swaps [Member] Five Year [Member]	Jun. 30, 2011 Interest Rate Swaps [Member] LNG Holdings [Member]	Jun. 30, 2011 Treasury Rate Locks [Member]	Jun. 30, 2011 Natural Gas Price Swaps [Member] Gathering And Processing [Member]	Jun. 30, 2011 Natural Gas Price Swaps [Member] Gathering And Processing [Member] Year 2011 [Member] MMBtu	Jun. 30, 2011 Natural Gas Price Swaps [Member] Gathering And Processing [Member] Year 2012 [Member] MMBtu	Jun. 30, 2011 Natural Gas Price Swaps [Member] Distribution [Member] Year 2011 [Member] MMBtu	Jun. 30, 2011 Natural Gas Price Swaps [Member] Distribution [Member] Year 2013 [Member] MMBtu	Jun. 30, 2011 NGL Price Swaps [Member] Gathering And Processing [Member]	Jun. 30, 2011 NGL Price Swaps [Member] Gathering And Processing [Member] MMBtus [Member] MMBtu	Jun. 30, 2011 NGL Price Swaps [Member] Gathering And Processing [Member] Gallons [Member] Gallons	Jun. 30, 2011 NGL Price Swaps [Member] Distribution [Member] Year 2012 [Member] MMBtu	Jun. 30, 2011 NGL Processing Spread Swaps [Member] Gathering And Processing [Member] MMBtu
Derivative Line Items
Derivative Notional Amount			$ 525,000,000	$ 450,000,000	$ 75,000,000	$ 455,000,000
Derivative Description Of Variable Rate Basis		three-month LIBOR plus a credit spread of 3.0175 percent
Derivative Ineffectiveness			no swap ineffectiveness
Derivative Fixed Interest Rate			3.63%
Cash Flow Hedge Gain Loss To Be Reclassified Within Twelve Months			14,200,000				571,000	6,000,000					1,600,000
Derivative Nonmonetary Notional Amount									8,280,000	3,660,000	8,490,000	2,020,000		5,490,000	65,378,124	14,270,000	4,600,000
Derivative Net Liability Position Aggregate Fair Value	$ 8,000,000

XML



Reportable Segments 2 Parentheticals (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Capital Expenditures [Abstract]
Increase Decrease Capital Accruals	$ 10.4	$ 7.9	$ 26.0	$ (7.9)

XML



Debt Obligations 2 Narrative (Details) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011
Debt Instrument Line Items
Debt Instrument, Face Amount	$ 550
Interest and Fee Rate Bases	LIBOR plus 162.5 basis points and 25 basis points

XML



Benefits (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost Abstract
Service cost	$ 935	$ 768	$ 1,870	$ 1,535
Interest cost	2,525	2,509	5,050	5,019
Expected return on plan assets	(2,647)	(2,337)	(5,293)	(4,674)
Prior service cost (credit) amortization	147	138	294	276
Actuarial loss (gain) amortization	1,984	1,996	3,967	3,993
Net periodic benefit cost subtotal	2,944	3,074	5,888	6,149
Regulatory adjustment	191	52	383	157
Net periodic benefit cost	3,135	3,126	6,271	6,306
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost Abstract
Service cost	881	793	1,761	1,586
Interest cost	1,446	1,409	2,892	2,819
Expected return on plan assets	(1,450)	(1,269)	(2,899)	(2,311)
Prior service cost (credit) amortization	(453)	(411)	(906)	(823)
Actuarial loss (gain) amortization	(403)	(451)	(806)	(901)
Net periodic benefit cost subtotal	21	71	42	370
Regulatory adjustment	666	666	1,332	1,332
Net periodic benefit cost	$ 687	$ 737	$ 1,374	$ 1,702

XML



Commitments and Contingencies 1 (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Environmental Liabilities [Line Items]
Current	$ 5,890	$ 10,648
Noncurrent	15,517	11,920
Total environmental liabilities	$ 21,407	$ 22,568

XML



Earnings per Share 2 (Details) (USD $) Share data in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Antidilutive Securities Excluded From Computation Of Earnings Per Share Line Items
Options and SARs excluded		1,235		1,235
Exercise Price Range Of Options and SARs Excluded	N/A	24.06 - 28.48	N/A	24.06 - 28.48
Year to Date Weighted Average Market Price	$ 30.11	$ 23.70	$ 28.67	$ 23.73