suform10q_63009.htm

10-Q 1 suform10q_63009.htm SOUTHERN UNION COMPANY FORM 10-Q JUNE 30, 2009 suform10q_63009.htm

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, 2009

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 P No___

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

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

Large accelerated filer P Accelerated filer __ Non-accelerated filer __ (Do not check if smaller reporting company) 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 P

The number of shares of the registrant's Common Stock outstanding on July 31, 2009 was 124,056,552.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

June 30, 2009

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)
Glossary	2
ITEM 1. Financial Statements (Unaudited):

Condensed consolidated statement of operations.	3

Condensed consolidated balance sheet.	4-5

Condensed consolidated statement of cash flows.	6

Condensed consolidated statement of stockholders’ equity and comprehensive income.	7

Notes to condensed consolidated financial statements.	8

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	32

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	47

ITEM 4. Controls and Procedures.	50

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.	51

ITEM 1A. Risk Factors.	52

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	52

ITEM 3. Defaults Upon Senior Securities.	52

ITEM 4. Submission of Matters to a Vote of Security Holders.	52

ITEM 5. Other Information.	53

ITEM 6. Exhibits.	53

SIGNATURES	58

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

Exchange Act Securities Exchange Act of 1934

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

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

Florida Gas Florida Gas Transmission Company, LLC

FSP FASB Staff Position

GAAP Accounting principles generally accepted in the United States of America

GDA Gas Daily Average

Grey Ranch Grey Ranch Plant, LP

IEPA Illinois Environmental Protection Agency

IFERC Inside FERC

IPCB Illinois Pollution Control Board

IRS Internal Revenue Service

KDHE Kansas Department of Health and Environment

LNG Liquified 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

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

RFP Request for Proposal

RIDEM Rhode Island Department of Environmental Management

SARs Stock appreciation rights

Sea Robin Sea Robin Pipeline Company, LLC

SEC Securities and Exchange Commission

Southern Union Southern Union Company

Southwest Gas Pan Gas Storage, LLC (d.b.a. Southwest Gas)

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands, except per share amounts)

Operating revenues (Note 13)	$	453,025		$	733,055		$	1,136,888		$	1,685,753

Operating expenses:
Cost of gas and other energy		191,917			459,032			571,979			1,069,201
Operating, maintenance and general		116,539			116,279			245,216			225,189
Depreciation and amortization		53,360			49,321			105,830			97,944
Revenue-related taxes		4,816			5,974			22,022			24,924
Taxes, other than on income and revenues		13,739			12,172			27,480			24,663
Total operating expenses		380,371			642,778			972,527			1,441,921

Operating income		72,654			90,277			164,361			243,832

Other income (expenses):
Interest expense		(48,365	)		(50,603	)		(96,735	)		(101,304	)
Earnings from unconsolidated investments		22,694			21,098			39,267			37,827
Other, net		132			720			6,094			1,058
Total other income (expenses), net		(25,539	)		(28,785	)		(51,374	)		(62,419	)

Earnings before income taxes		47,115			61,492			112,987			181,413

Federal and state income tax expense (Note 9)		13,835			18,582			33,450			55,595


Net earnings		33,280			42,910			79,537			125,818

Preferred stock dividends		(2,170	)		(3,436	)		(4,341	)		(7,777	)

Loss on extinguishment of preferred stock		-			(1,995	)		-			(1,995	)

Net earnings available for common stockholders	$	31,110		$	37,479		$	75,196		$	116,046

Net earnings available for common stockholders per share:
Basic	$	0.25		$	0.30		$	0.61		$	0.94
Diluted		0.25			0.30			0.61			0.94

Dividends declared on common stock per share	$	0.15		$	0.15		$	0.30		$	0.30

Weighted average shares outstanding (Note 4):
Basic		124,047			124,008			124,046			122,905
Diluted		124,274			124,242			124,123			123,188

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

		June 30,		December 31,
		2009		2008
		(In thousands)
Current assets:
Cash and cash equivalents	$	15,232	$	4,318
Accounts receivable, net of allowances of
$8,056 and $6,003, respectively		207,256		327,358
Accounts receivable – affiliates		9,620		14,743
Inventories (Note 3)		254,113		337,858
Deferred gas purchases		71,487		64,330
Gas imbalances - receivable		127,035		174,100
Derivative instruments (Notes 10 and 11)		32,445		91,423
Prepayments and other assets		8,949		18,226
Total current assets		726,137		1,032,356

Property, plant and equipment:
Plant in service		6,107,921		5,980,297
Construction work in progress		516,802		451,359
		6,624,723		6,431,656
Less accumulated depreciation and amortization		(1,090,334)		(974,651)
Net property, plant and equipment		5,534,389		5,457,005

Deferred charges:
Regulatory assets		74,070		69,554
Deferred charges		54,776		59,958
Total deferred charges		128,846		129,512

Unconsolidated investments (Note 5)		1,297,884		1,259,270

Goodwill		89,227		89,227

Other		25,469		30,537


Total assets	$	7,801,952	$	7,997,907

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	June 30,			December 31,
	2009			2008
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
125,167 and 125,122 shares issued, respectively	$	125,167		$	125,122
Preferred stock, no par value; 6,000 shares authorized;
460 and 460 shares issued, respectively		115,000			115,000
Premium on capital stock		1,897,342			1,893,975
Less treasury stock: 1,120 and 1,120
shares, respectively, at cost		(28,004	)		(28,004	)
Less common stock held in trust: 639
and 663 shares, respectively		(11,395	)		(11,908	)
Deferred compensation plans		11,395			11,908
Accumulated other comprehensive loss		(49,992	)		(51,423	)
Retained earnings		351,264			313,282
Total stockholders' equity		2,410,777			2,367,952

Long-term debt obligations (Note 7)		3,267,889			3,257,434

Total capitalization		5,678,666			5,625,386

Current liabilities:
Long-term debt due within one year (Note 7)		201,123			60,623
Notes payable		150,000			401,459
Accounts payable and accrued liabilities		186,360			246,884
Federal, state and local taxes payable		51,753			54,027
Accrued interest		41,476			41,141
Gas imbalances - payable		262,342			341,987
Derivative instruments (Notes 10 and 11)		83,266			77,554
Other		122,157			128,190
Total current liabilities		1,098,477			1,351,865

Deferred credits		263,542			298,106

Accumulated deferred income taxes		761,267			722,550

Commitments and contingencies (Note 12)

Total stockholders' equity and liabilities	$	7,801,952		$	7,997,907

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)


	Six Months Ended June 30,
	2009			2008
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	79,537		$	125,818
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		105,830			97,944
Deferred income taxes		28,546			47,444
Unrealized loss on commodity derivatives		20,681			19,126
Earnings from unconsolidated investments, adjusted
for cash distributions		(39,267	)		2,923
Provision for bad debts		11,109			10,514
Share-based compensation expense		3,622			2,871
Changes in operating assets and liabilities		171,767			40,704
Net cash flows provided by operating activities		381,825			347,344
Cash flows used in investing activities:
Additions to property, plant and equipment		(227,257	)		(342,728	)
Plant retirements and other		(3,114	)		(2,814	)
Net cash flows used in investing activities		(230,371	)		(345,542	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		2,273			(6,237	)
Issuance cost of debt		(1,128	)		(3,867	)
Issuance of common stock		-			100,000
Issuance of long-term debt		151,533			400,000
Dividends paid on common stock		(37,208	)		(36,590	)
Dividends paid on preferred stock		(4,341	)		(8,682	)
Extinguishment of preferred stock		-			(48,592	)
Repayment of debt obligation		-			(51,829	)
Net change in revolving credit facilities		(251,459	)		(123,000	)
Proceeds from exercise of stock options		-			3,846
Other		(210	)		(1,222	)
Net cash flows provided by (used in) financing activities		(140,540	)		223,827
Change in cash and cash equivalents		10,914			225,629
Cash and cash equivalents at beginning of period		4,318			5,690
Cash and cash equivalents at end of period	$	15,232		$	231,319

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common		Preferred		Premium						Common			Deferred			Accumulated						Total
	Stock,		Stock,		on			Treasury			Stock			Compen-			Other						Stock-
	$1 Par		No Par		Capital			Stock,			Held			sation			Comprehensive			Retained			holders'
	Value		Value		Stock			at cost			In Trust			Plans			Loss			Earnings			Equity
	(In thousands)

Balance December 31, 2008	$	125,122	$	115,000	$	1,893,975		$	(28,004	)	$	(11,908	)	$	11,908		$	(51,423	)	$	313,282		$	2,367,952
Comprehensive income:
Net earnings		-		-		-			-			-			-			-			79,537			79,537
Net change in other
comprehensive income (Note 6)		-		-		-			-			-			-			1,431			-			1,431
Comprehensive income																								80,968
Preferred stock dividends		-		-		-			-			-			-			-			(4,341	)		(4,341	)
Common stock dividends declared		-		-		-			-			-			-			-			(37,214	)		(37,214	)
Share-based compensation		-		-		3,622			-			-			-			-			-			3,622
Restricted stock issuances		45		-		(255	)		-			-			-			-			-			(210	)
Contributions to Trust		-		-		-			-			(632	)		632			-			-			-
Disbursements from Trust		-		-		-			-			1,145			(1,145	)		-			-			-
Balance June 30, 2009	$	125,167	$	115,000	$	1,897,342		$	(28,004	)	$	(11,395	)	$	11,395		$	(49,992	)	$	351,264		$	2,410,777

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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the SEC for quarterly reports on Form 10-Q. These statements do not include all of the information and annual note disclosures required by GAAP, and should be read in conjunction with the Company’s financial statements and notes thereto for the year ended December 31, 2008, 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 Company evaluated subsequent events through August 6, 2009, the date on which this Quarterly Report on Form 10-Q was issued.

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. Certain reclassifications have been made to the prior year’s condensed financial statements to conform to the current year presentation.

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, 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 the gathering, treating, processing and redelivery of natural gas and NGL in West Texas and Southeast New Mexico. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

2. New Accounting Principles and Other Matters

Accounting Principles Recently Adopted.

FASB Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”. Issued by the FASB in March 2008, this Statement expands the disclosure requirements associated with derivative instruments to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Statement is effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. See Note 10 – Derivative Instruments and Hedging Activities, which reflects the disclosure required by this Statement.

FASB Statement No. 165, "Subsequent Events". Issued by the FASB in June 2009, this Statement establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. This Statement establishes (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This Statement is effective for interim or annual financial periods ending after June 15, 2009.

FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP FAS 157-4). Issued by the FASB in April 2009, this FSP provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and also includes guidance on identifying circumstances that indicate a transaction is not orderly. The provisions of FSP FAS 157-4 are applied prospectively and are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted FSP FAS 157-4 in the first quarter of 2009. The impact of FSP FAS 157-4 was not material to the Company’s consolidated financial statements.

FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1). Issued by the FASB in April 2009, this FSP requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also requires those disclosures in summarized financial information at interim reporting periods. The provisions of FSP FAS 107-1 and APB 28-1 are effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company early adopted FSP FAS 107-1 and APB 28-1 in the first quarter of 2009, resulting in the disclosure of certain fair value information associated with the Company’s debt obligations. See Note 7 – Debt Obligations for the related information.

Accounting Principles Not Yet Adopted.

FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1). Issued by the FASB in December 2008, FSP FAS 132(R)-1 provides guidance on an employer’s disclosure about plan assets of a defined benefit pension or other postretirement plan. The provisions of FSP FAS 132(R)-1 are effective for fiscal years ending after December 15, 2009. The Company is currently evaluating the impact of this FSP on its consolidated financial statements, which will be required to be included in the Company’s Annual Report on Form 10-K for the year ending December 31, 2009.

FASB Statement No. 167, “New Consolidation Guidance for Variable Interest Entities.” Issued by the FASB in June 2009, this Statement changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly affect the entity’s economic performance. The Statement is effective after November 15, 2009, with early adoption prohibited. The Company does not expect this Statement to materially impact its consolidated financial statements.

Accounting Standards Codification. The FASB Accounting Standards Codification (Codification) became effective on July 1, 2009, officially becoming the single source of authoritative nongovernmental GAAP, superseding existing FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force, and related accounting literature. Only one level of authoritative GAAP now exists. All other accounting literature is considered non-authoritative. The Codification reorganizes the thousands of GAAP pronouncements into roughly 90 accounting topics and displays them using a consistent structure. Also included in the Codification is relevant SEC guidance organized using the same topical structure in separate sections within the Codification. The Codification will be effective for financial statements that cover interim and annual periods ending after September 15, 2009. The Company’s financial statements will only be impacted to the extent that all future references to authoritative accounting literature will be referenced in accordance with the Codification.

Other Matters.

Asset Impairment. An impairment loss is recognized when the carrying amount of a long-lived asset used in operations is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value.

A long-lived asset is tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. The long-lived assets of Sea Robin were evaluated as of December 31, 2008 and June 30, 2009 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricane Ike and due to reductions in the estimated payout from the Company’s insurance carrier for reimbursable expenditures for the repair, retirement or replacement of the Company’s property, plant and equipment damaged by Hurricane Ike, which is more fully discussed in Note 12 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage. Based upon the Company’s analysis, no impairment of the carrying value of the Sea Robin assets has occurred at this time.

3. Inventories

In the Transportation and Storage segment, inventories consist of natural gas held for operations and materials and supplies, both of which are stated at the lower of weighted average cost or market, while gas received from or owed back to customers is valued at market. The gas held for operations that the Company does not expect to consume in its operations in the next twelve months is reflected in non-current assets.

In the Gathering and Processing segment, inventories consist of non-fractionated Y-grade NGL and materials and supplies, both of which are stated at the lower of weighted average cost or market. Materials and supplies are primarily comprised of compressor components and parts.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies. The natural gas in underground storage inventory carrying value is stated at weighted average cost and is not adjusted to a lower market value because, pursuant to purchased natural gas adjustment clauses, actual natural gas costs are recovered in customers’ rates. Materials and supplies inventory is also stated at weighted average cost.

The components of inventory at the dates indicated are as follows:

	Transportation & Storage		Gathering & Processing		Distribution		Total
At June 30, 2009	(In thousands)
Current
Natural gas held for operations (1)	$	154,954	$	-	$	-	$	154,954
Materials and Supplies		15,284		9,256		4,351		28,891
NGL (2)		-		717		-		717
Natural gas in underground storage (3)		-		-		69,551		69,551
Total Current		170,238		9,973		73,902		254,113

Non-Current
Natural gas held for operations (1)		12,352		-		-		12,352

	$	182,590	$	9,973	$	73,902	$	266,465


At December 31, 2008
Current
Natural gas held for operations (1)	$	182,547	$	-	$	-	$	182,547
Materials and Supplies		14,056		9,278		4,488		27,822
NGL (2)		-		8,521		-		8,521
Natural gas in underground storage (3)		-		-		118,968		118,968
Total Current		196,603		17,799		123,456		337,858

Non-Current
Natural gas held for operations (1)		17,687		-		-		17,687

	$	214,290	$	17,799	$	123,456	$	355,545

____________________

(1)	Natural gas volumes held for operations at June 30, 2009 and December 31, 2008 were 31,867,000 MMBtu and 31,751,000 MMBtu, respectively.

(2)	NGL at June 30, 2009 and December 31, 2008 was 1,449,000 gallons and 20,453,000 gallons, respectively.

(3)	Natural gas volumes in underground storage at June 30, 2009 and December 31, 2008 were 12,751,000 MMBtu and 12,702,000 MMBtu, respectively.

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.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands)

Weighted average shares outstanding - Basic		124,047		124,008		124,046		122,905
Add assumed vesting of restricted stock		64		15		48		16
Add assumed exercise of stock options and SARs		163		219		29		267
Weighted average shares outstanding - Diluted		124,274		124,242		124,123		123,188

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.

	June 30,
	2009	2008
	(In thousands, except per share amounts)

Options excluded	1,662	717
Exercise price of options excluded	$16.83 - $28.48	$28.48
SARs excluded	386	416
Exercise price ranges of SARs excluded	$28.07 - $28.48	$28.07 - $28.48
Second quarter weighted-average market price	$16.56	$25.73
Year-to-date weighted-average market price	$15.14	$26.06

5. Unconsolidated Investments

A summary of the Company’s unconsolidated equity investments at the dates indicated is as follows:

	June 30,		December 31,
Unconsolidated Investments	2009		2008
	(In thousands)
Equity investments:
Citrus	$	1,276,044	$	1,238,198
Other		21,840		21,072
	$	1,297,884	$	1,259,270

Equity Investments. Unconsolidated investments at June 30, 2009 and December 31, 2008 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus, Grey Ranch, Lee 8 Partnership and PEI II, LLC, respectively. 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.

Summarized financial information for the Company’s equity investments is as follows:

	Three Months Ended June 30,
	2009				2008
	Citrus		Other		Citrus		Other
	(In thousands)

Revenues	$	136,781	$	3,717	$	134,901	$	3,648
Operating income		77,949		2,010		79,432		496
Net earnings		38,092		1,935		37,206		(264)


	Six Months Ended June 30,
		2009
	Citrus		Other		Citrus		Other
	(In thousands)

Revenues	$	248,223	$	9,107	$	247,225	$	8,010
Operating income		132,543		3,920		136,937		1,957
Net earnings		64,514		3,831		63,637		1,176

Citrus.

Dividends. Citrus did not pay dividends to the Company during the six-month period ended June 30, 2009. In the three- and six-month periods ended June 30, 2008, Citrus paid dividends of nil and $40.8 million, respectively, to the Company.

Phase VIII Expansion. Florida Gas, a wholly-owned subsidiary of Citrus, filed a certificate application on October 31, 2008 with FERC to construct an expansion to increase its natural gas capacity into Florida by approximately 820 MMcf/d (Phase VIII Expansion). The proposed Phase VIII Expansion includes construction of approximately 500 miles of large diameter pipeline and the installation of approximately 200,000 horsepower of compression. Pending FERC approval, which is expected in the latter half of 2009, Florida Gas anticipates an in-service date during 2011, at a currently estimated cost of $2.4 billion, including capitalized equity and debt costs. To date, Florida Gas has entered into precedent agreements with shippers for transportation services for 25-year terms accounting for approximately 74 percent of the available expansion capacity which, depending on elections by one of the shippers, may increase to 83 percent of such capacity.

Florida Gas Debt Issuance. In May 2009, Florida Gas issued $600 million of 7.90 percent senior notes due May 15, 2019 with an offering price of $99.82 (per $100 principal). Florida Gas will use the net proceeds to partially fund the Phase VIII Expansion project and for general corporate purposes.

Florida Gas Swap Rate Lock Agreements. In July 2009, Citrus entered into a series of forward starting swap rate lock agreements (Swap Rate Lock Agreements) with a total notional amount of $175 million with regard to the expected conversion of the $500 million construction and term loan agreement (Construction Loan Agreement) that it entered into in February 2008. The Swap Rate Lock Agreements are designed to hedge against the potential changes in future cash flows payable under the Construction Loan Agreement when it is converted to a twenty-year fixed rate term loan, which is projected to occur on or before April 1, 2011.

Florida Gas Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. A dispute exists with the FDOT/FTE over the rights of Florida Gas under certain easements and other agreements associated with the State Road 91 projects to, among other matters, receive reimbursement for the relocation costs incurred by Florida Gas and the nature and scope of such easements. The first phase of the State Road 91 projects included replacement of approximately 11.3 miles of the existing 18- and 24-inch pipelines in Broward County, Florida due to the widening of State Road 91 by the FDOT/FTE. Construction is complete and the new facilities were placed in service in March 2008. The FDOT/FTE plans additional projects that may affect Florida Gas’ pipelines within FDOT/FTE rights-of-way. The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects and any associated relocation and/or rights-of-way costs, cannot be determined at this time.

The various FDOT/FTE projects are the subject of state court litigation. In January 2007, Florida Gas filed a complaint against FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three specific sets of FDOT/FTE widening projects in Broward County. The case was subsequently transferred to the Broward County Complex Business Civil Division 07. The complaint seeks damages for the breach of easement and relocation agreements for the completed State Road 91 relocation project and injunctive relief as well as damages for the two other sets of projects upon which construction has yet to commence. The FDOT/FTE filed counterclaims against Florida Gas alleging, among other matters, that Florida Gas is subject to estoppel, claims for breach of contract, trespass, unjust enrichment, and fraud in the inducement regarding the removal from service of the existing 18- and 24-inch pipelines. Further, the FDOT/FTE is seeking to place a constructive trust over any revenues associated with the previously existing and newly constructed pipelines and to obtain a declaratory judgment that Florida Gas is responsible for all relocation costs and is not entitled to workspace and uniform minimum area with respect to its pipelines. The Court has allowed the FDOT/FTE to include counts of fraud and trespass in its counterclaim. Florida Gas contends the Court reserved ruling on permitting a demand for punitive damages on those counts. The FDOT/FTE contends that the Court authorized the demand for punitive damages when the Court allowed the counts of fraud and trespass. A supplemental motion for temporary injunction and a motion for partial summary judgment is pending against Florida Gas on the extent of the rights Florida Gas claims under the easements at issue, the breach of the easements by the FDOT/FTE for failing to provide adequate rights-of-way, the failure of the FDOT/FTE to reimburse Florida Gas for the costs of relocation, and inverse condemnation as a result of the FDOT/FTE’s claim that Florida Gas breached the easements. The FDOT/FTE is claiming approximately $30 million in actual damages based on the most current information provided by the FDOT/FTE. The FDOT/FTE is seeking the Court’s permission to supplement these claims with as yet undetermined amounts associated with its claim for a constructive trust over revenues from the subject pipelines for the period April 2008 through January 2009. A hearing will be held in September 2009 to establish a trial date; trial had previously been set for August 2009.

A 2007 action brought by the FDOT/FTE against Florida Gas in Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with FDOT/FTE projects, has been stayed pending resolution of the Broward County, Florida action.

Should Florida Gas be denied reimbursement by the FDOT/FTE for relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas expects to seek rate recovery at FERC for all reasonable and prudent costs incurred in relocating its pipelines due to the FDOT/FTE projects to the extent not reimbursed by the FDOT/FTE. There can be no assurance that Florida Gas will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate Florida Gas for its costs.

Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as high consequence areas (HCAs). The rule requires operators to identify and risk rank HCAs along their pipelines and perform baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessments. While identification and location of all HCAs and the majority of the required risk assessments has been completed by Florida Gas, it is not practicable to determine with certainty the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections are currently estimated to be in the range of approximately $20 million to $28 million per year through 2012.

In addition to the cost of the HCA requirements, Florida Gas is required under other regulations from time to time to undertake certain actions that may include testing or upgrading portions of its system by pipeline replacement. Florida Gas anticipates total expenditures of approximately $175 million in 2009 and 2010 to meet these requirements. Due to the nature of the factors affecting these costs, it is anticipated that future annual costs will decline significantly from the expected 2009-2010 levels.

Litigation – Jack Grynberg. Jack Grynberg, an individual, filed actions for damages against a number of companies, including Florida Gas, alleging mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. For additional information related to these filed actions, see Note 13 – Commitments and Contingencies – Litigation.

6. Comprehensive Income (Loss)

The table below provides an overview of changes in Comprehensive income (loss) for the periods indicated:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Comprehensive Income (Loss)	2009			2008			2009			2008
	(In thousands)

Net Earnings	$	33,280		$	42,910		$	79,537		$	125,818
Changes in Other Comprehensive Income (Loss):
Change in fair value of interest rate hedges, net of tax of $827,
$11,472, $412 and $(994), respectively		1,231			17,614			613			(1,405	)
Reclassification of unrealized loss on interest rate hedges
into earnings, net of tax of $1,964, $1,309, $3,576 and $1,698,
respectively		2,950			1,988			5,379			2,597
Realized gain (loss) on interest rate hedges, net of tax of $0, $197,
$0 and $(620), respectively		-			309			-			(1,175	)
Change in fair value of commodity hedges, net of tax of $(81),
$(9,662), $4,507 and $(14,250), respectively		(143	)		(17,149	)		7,999			(25,290	)
Reclassification of unrealized (gain) loss on commodity hedges
into earnings, net of tax of $(4,207), $1,566, $(8,174) and $1,620,
respectively		(7,466	)		2,778			(14,506	)		2,874
Prior service cost relating to other postretirement benefit
plan amendment, net of tax of $0, $0, $0 and $(3,231),
respectively		-			-			-			(6,603	)
Reclassification of net actuarial loss and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $736, $520, $1,472 and $951, respectively		974			816			1,946			1,459
Total other comprehensive income (loss)		(2,454	)		6,356			1,431			(27,543	)
Total comprehensive income	$	30,826		$	49,266		$	80,968		$	98,275

See Note 8 – Employee Benefits for a discussion related to an amendment of Panhandle’s other postretirement benefit plan in March 2008, which resulted in a $6.6 million net of tax reduction in the net prior service credit included in Accumulated other comprehensive loss.

7. Debt Obligations

The following table sets forth the debt obligations of Southern Union and applicable units of Panhandle under their respective notes, debentures and bonds at the dates indicated:


	June 30, 2009				December 31, 2008
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Long-Term Debt Obligations:

Southern Union
7.60% Senior Notes due 2024	$	359,765	$	355,563	$	359,765	$	272,165
8.25% Senior Notes due 2029		300,000		282,372		300,000		229,470
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		19,471		19,500		16,248
6.089% Senior Notes due 2010		100,000		100,241		100,000		92,701
7.20% Junior Subordinated Notes due 2066		600,000		408,000		600,000		215,999
Note Payable		5,353		5,353		3,820		3,820
		1,384,618		1,171,000		1,383,085		830,403

Panhandle
6.05% Senior Notes due 2013		250,000		255,440		250,000		211,646
6.20% Senior Notes due 2017		300,000		288,780		300,000		230,956
6.50% Senior Notes due 2009		60,623		60,623		60,623		59,604
8.125% Senior Notes due 2019		150,000		160,155		-		-
8.25% Senior Notes due 2010		40,500		41,841		40,500		39,668
7.00% Senior Notes due 2029		66,305		63,289		66,305		46,158
7.00% Senior Notes due 2018		400,000		424,936		400,000		318,033
Term Loans due 2012		815,391		746,398		815,391		753,262
Net premiums on long-term debt		1,575		1,575		2,153		2,153
		2,084,394		2,043,037		1,934,972		1,661,480

Total Long-Term Debt Obligations		3,469,012		3,214,037		3,318,057		2,491,883

Credit Facilities		-		-		251,459		243,205
Short-Term Facility		150,000		150,000		150,000		148,496

Total consolidated debt obligations		3,619,012	$	3,364,037		3,719,516	$	2,883,584
Less current portion of long-term debt		201,123				60,623
Less short-term debt		150,000				401,459
Total long-term debt	$	3,267,889			$	3,257,434

The fair value of the Company’s Term Loans due 2012, the Credit Facilities and the Short-Term Facility as of June 30, 2009 and December 31, 2008 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 that type and size.

The fair value of the Company’s other long-term debt as of June 30, 2009 and December 31, 2008 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.

8.125% Senior Notes. In June 2009, PEPL issued $150 million in senior notes due June 1, 2019 with an interest rate of 8.125 percent (8.125% Senior Notes). In connection with the issuance of the 8.125% Senior Notes, PEPL incurred underwriting and discount costs totaling approximately $1 million, resulting in approximately $149 million in proceeds to PEPL. These proceeds were used to repay borrowings under the Company’s Credit Facilities and to repay the $60.6 million of 6.50% Senior Notes that matured on July 15, 2009.

2009 Term Loan. On August 5, 2009, the Company entered into a two-year $150 million term loan (2009 Term Loan) with a syndicate of banks. The interest rate associated with the 2009 Term Loan is based, at the Company’s option, upon either LIBOR or the prime lending rate, plus a credit spread based upon the Company’s credit ratings. Borrowings under the 2009 Term Loan are available for general corporate purposes. The proceeds of the 2009 Term Loan were used to repay borrowings under the Credit Faciltiies.

8. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the three-month periods ended June 30, 2009 and 2008 includes the components noted in the table below.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
	(In thousands)

Service cost	$	737		$	686		$	750		$	689
Interest cost		2,524			2,470			1,347			1,405
Expected return on plan assets		(2,070	)		(2,877	)		(772	)		(832	)
Prior service cost (credit) amortization		138			138			(317	)		(213	)
Recognized actuarial (gain) loss		2,102			1,716			(212	)		(306	)
Sub-total		3,431			2,133			796			743
Regulatory adjustment (1)		(125	)		704			666			666
Net periodic benefit cost	$	3,306		$	2,837		$	1,462		$	1,409

Net periodic benefit cost for the six-month periods ended June 30, 2009 and 2008 includes the components noted in the table below.

	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In thousands)

Service cost	$	1,475		$	1,372		$	1,499		$	1,253
Interest cost		5,048			4,940			2,695			2,685
Expected return on plan assets		(4,140	)		(5,754	)		(1,544	)		(1,639	)
Prior service cost (credit) amortization		276			276			(634	)		(676	)
Recognized actuarial (gain) loss		4,203			3,433			(424	)		(612	)
Sub-total		6,862			4,267			1,592			1,011
Regulatory adjustment (1)		(250	)		1,409			1,332			1,332
Net periodic benefit cost	$	6,612		$	5,676		$	2,924		$	2,343

____________________

(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 amounts and 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.

In March 2008, a postretirement benefit plan change was approved for Panhandle for retirements beginning April 1, 2008. The change resulted in a pre-tax postretirement benefit obligation increase of approximately $9.8 million.

9. Taxes on Income

The Company’s income taxes were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands)

Income tax expense	$	13,835	$	18,582	$	33,450	$	55,595
Effective tax rate		29%		30%		30%		31%

The decrease in the EITR for the three-month and six-month periods ended June 30, 2009 versus the same periods in 2008 was primarily due to the following:

Lower state income tax expense, net of the federal income tax benefit. For the three months ended June 30, 2009 and 2008, the state income tax expense, net of federal benefit, was $1.4 million and $2.2 million, respectively. For the six-month periods ended June 30, 2009 and 2008, the state income tax expense, net of federal benefit, was $3 million and $5.5 million, respectively; and

An increase in the tax benefit (relative to lower pretax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus. For the three-month periods ended June 30, 2009 and 2008, the tax benefit of the dividends received deduction was $4.2 million and $4.8 million, respectively. For the six-month periods ended June 30, 2009 and 2008, the tax benefit of the dividends received deduction was $9.4 million and $13.8 million, respectively.

The Company accounts for uncertainty in income taxes in measuring its current or deferred income tax assets and liabilities. The Company evaluates these uncertainties (unrecognized tax benefits) under a more-likely-than-not recognition, measurement and derecognition threshold for tax positions it has taken in previously filed tax returns or tax positions expected to be taken in a future tax return. The Company increased the amount of its unrecognized tax benefits for certain state filing positions taken during the current period by $660,000 ($440,000, net of federal tax) and $1.3 million ($870,000, net of federal tax) during the three- and six-month periods ended June 30, 2009, respectively. The Company currently has $8.5 million ($5.6 million, net of federal tax) of unrecognized tax benefits as of June 30, 2009, all of which would impact the Company’s EITR if recognized. The Company believes it is reasonably possible that its unrecognized tax benefits may be reduced by $1.1 million ($750,000, net of federal tax) within the next twelve months due to settlement of certain state filing positions.

The Company is no longer subject to examination and assessment by U.S. federal, state or local jurisdictions for the tax period ended December 31, 2004 and prior years, except for a few state and local jurisdictions for the tax year ended June 30, 2003. The Company settled the IRS examination of the year ended June 30, 2003 in November 2006. Generally, the state impact of the federal change remains subject to state and local examination for a period of up to one year after formal notification to the state and local jurisdictions. In 2007, the Company filed all required state amended returns as a result of the federal change. With a few exceptions, the state and local statutes have expired with respect to the tax year ended June 30, 2003.

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

Interest Rate Contracts

The Company enters 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 enters 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. As of June 30, 2009, the Company had outstanding pay-fixed interest rate swaps with a total notional amount of $455 million. 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, 2009, approximately $11.5 million of net after-tax losses 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, 2009, 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 were/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, 2009, approximately $1 million 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 enters into natural gas price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of equity (Company-owned) natural gas and NGL volumes resulting from movements in market commodity prices.

Natural Gas Price Swaps. As of June 30, 2009, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 7,360,000 MMBtus and 9,125,000 MMBtus for the remainder of 2009 and 2010, respectively. 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, 2009, approximately $14.2 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps is 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, 2009, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 6,440,000 MMBtu equivalents for the remainder of 2009. These processing spread swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues.

The Company enters into other derivative instruments, including natural gas price swaps, basis swaps and futures, to manage its exposure to changes in margin on sales of non-equity natural gas volumes made at fixed prices or delivery points different from supply points, resulting from movements in market commodity prices.

Other Derivative Instruments. As of June 30, 2009, the Company had outstanding forward contracts for the sale of 428,965 MMBtus and 390,000 MMBtus of natural gas at fixed prices for the remainder of 2009 and 2010, respectively. These forward contracts are derivatives with changes in their fair value recorded in Operating revenues. As of June 30, 2009, the Company had outstanding receive-floating natural gas price swaps, NYMEX futures and NYMEX to WAHA basis swaps with total notional amounts of 227,500 MMBtus, 20,000 MMBtus and 400,000 MMBtus, respectively, that are associated with the 2009 forward contracts, and outstanding NYMEX futures and NYMEX to WAHA basis swaps with total notional amounts of 390,000 MMBtus and 390,000 MMBtus, respectively, that are associated with the 2010 forward contracts. These natural gas price swaps, futures and basis swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues. As of June 30, 2009, the Company had outstanding WAHA to Houston Ship basis swaps that are associated with the delivery of 10,000 MMBtu/d of natural gas through November 2009 at delivery points different from supply points and outstanding GDA to IFERC index swaps that are associated with the sale of 5,000 MMBtu/d of natural gas for July 2009 at index pricing different from supply index pricing. These natural gas basis and index 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 price swaps to manage the exposure to changes in the cost of forecasted purchases 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 gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.

Natural Gas Price Swaps. As of June 30, 2009, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 9,610,000 MMBtus, 18,930,000 MMBtus and 4,020,000 MMBtus for the remainder of 2009, 2010 and 2011, respectively. These natural gas price swaps are accounted for as economic hedges, with changes in their fair value recorded to Deferred charges – regulatory assets.

Summary Financial Statement Information

The following table summarizes the fair value amounts of the Company’s derivative instruments and their respective location reported in the Condensed Consolidated Balance Sheet at June 30, 2009.

	Asset Derivatives			Liability Derivatives
Balance Sheet		Fair		Balance Sheet	Fair
Location		Value (1)		Location	Value (1)
		(In thousands)			(In thousands)
Cash Flow Hedges
Interest rate contracts:
Interest rate swaps		$	-	Derivative instruments-liabilities	$	17,040
				Deferred credits		17,651
Commodity contracts - Gathering and Processing:
Natural gas price swaps	Derivative instruments-assets		22,154	Deferred credits		1,575
		$	22,154		$	36,266
Economic Hedges
Commodity contracts - Gathering and Processing:
NGL processing spread swaps	Derivative instruments-assets	$	9,345		$	-
Other derivative instruments	Derivative instruments-liabilities		524	Derivative instruments-liabilities		1,003
Derivative instruments-assets			145			-

Commodity contracts - Distribution:
Natural gas price swaps	Derivative instruments-liabilities		112	Derivative instruments-liabilities		65,859
Deferred credits			257	Deferred credits		5,472
		$	10,383		$	72,334
Other
Commodity contracts - Gathering and Processing:
Other derivative instruments	Derivative instruments-assets	$	813	Derivative instruments-assets	$	12

Total		$	33,350		$	108,612

_____________

(1)	See Note 11 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of June 30, 2009.

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 condensed consolidated financial statements for the periods presented.

	Three Months Ended			Six Months Ended
	June 30, 2009			June 30, 2009
Cash Flow Hedges (1)	(In thousands)
Interest rate contracts:
Change in fair value - decrease in Accumulated other comprehensive loss,
excluding tax expense effect of $827 and $412	$	2,058		$	1,025
Reclassification of unrealized loss from Accumulated other comprehensive loss -
increase of Interest expense, excluding tax expense effect of $(1,964)
and $(3,576)		4,914			8,955

Commodity contracts - Gathering and Processing:
Change in fair value - (increase)/decrease in Accumulated other comprehensive
loss, excluding tax expense effect of $(81) and $4,507		(224	)		12,506
Reclassification of unrealized gain from Accumulated other comprehensive loss -
increase of Operating revenues, excluding tax expense effect of $4,207
and $8,174		11,673			22,680

Economic Hedges
Commodity contracts - Gathering and Processing:
Change in fair value - decrease in Operating revenues		13,762			35,130

Commodity contracts - Distribution:
Change in fair value - decrease in Deferred charges - Regulatory assets		29,797			21,721

Other
Commodity contracts - Gathering and Processing:
Change in fair value - decrease in Operating revenues		451			162

_________________

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

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 request immediate payment. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position at June 30, 2009 is $21.5 million.

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 June 30, 2009.


			Fair Value Measurements Using Fair Value Hierarchy
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
At June 30, 2009	Fair Value		(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Assets:
Cash equivalents (money
market investments)	$	13,269	$	13,269	$	-	$	-
Commodity derivatives (1), (2)		32,445		-		32,445		-
Long-term investments		726		726		-		-
Total	$	46,440	$	13,995	$	32,445	$	-

Liabilities:
Commodity derivatives (2)	$	73,017	$	-	$	73,017	$	-
Interest-rate derivatives (2)		34,691		-		-		34,691
Total	$	107,708	$	-	$	73,017	$	34,691

__________________

(1)	The Company’s commodity derivative asset balance is primarily associated with two separate counterparties, each individually comprising $18.2 million and $13.3 million of the related fair value as of June 30, 2009.

(2)	See related information in Note 10 – Derivative Instruments and Hedging Activities.

The Company’s Level 3 instruments include interest-rate swap derivatives that are valued using an income approach where at least one significant assumption or input to the underlying pricing model is unobservable – i.e., interest rate swap valuations include composite yield curves developed by the bank counterparty. The liabilities that the Company has categorized in Level 3 may later be reclassified to Level 2 when the Company is able to obtain additional observable market data to corroborate the unobservable inputs to models used to measure the fair value of these liabilities. The Company’s Level 2 instruments primarily include natural gas and NGL processing spread swap derivatives that are valued based on pricing models where significant inputs are observable. The Company’s Level 1 instruments consist of money market mutual funds and trading securities related to a non-qualified deferred compensation plan that are valued based on active market quotes.

The following table provides a reconciliation of the change in the Company’s Level 3 assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the periods indicated.

	Assets			Liabilities
	Commodity			Commodity			Interest-rate
	Derivatives			Derivatives			Derivatives
	(In thousands)
Three Months Ended June 30, 2009
Beginning balance	$	-		$	-		$	41,143
Total gains or losses (realized and unrealized):
Included in operating revenues		-			-			-
Included in other comprehensive income		-			-			(2,244	)
Purchases and settlements, net		-			-			(4,208	)
Transfers out of level 3		-			-			-
Ending balance	$	-		$	-		$	34,691



Six Months Ended June 30, 2009
Beginning balance	$	964		$	(94	)	$	43,630
Total gains or losses (realized and unrealized):
Included in operating revenues (1)		290			61			-
Included in other comprehensive income		-			-			(1,301	)
Purchases and settlements, net		-			(206	)		(7,638	)
Transfers out of level 3 (2)		(1,254	)		239			-
Ending balance	$	-		$	-		$	34,691

___________________

(1)	The amounts included in operating revenues for the six months ended June 30, 2009 attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities were gains of $725,000 and $221,000, respectively.

(2)	Transfer to Level 2 was made effective March 31, 2009.

12. Commitments and Contingencies

Environmental

The Company’s operations are subject to federal, state and local laws and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements 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 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 Company is allowed to recover environmental remediation expenditures through rates in certain jurisdictions within its Distribution segment. Although significant charges to earnings could be required prior to rate recovery for jurisdictions that do not have rate recovery mechanisms, management does not believe that environmental expenditures will have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. The table below reflects the amount of accrued liabilities recorded in the unaudited interim Condensed Consolidated Balance Sheet at June 30, 2009 and December 31, 2008 to cover probable environmental response actions:

	June 30,	December 31,
	2009	2008
	(In thousands)

Current	$ 15,791	$ 3,513
Noncurrent	15,197	15,626
Total Environmental Liabilities	$ 30,988	$ 19,139

SPCC Rules. In October 2007, the EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. The most recent extension by the EPA sets the SPCC rule compliance dates as November 1, 2010, permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations. The Company is currently reviewing the impact of the modified regulations on 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 such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems. 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 developed and 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 amount of estimated costs to remediate PCBs at the Company’s facilities was increased in 2009 by approximately $1 million. The PCB assessments are ongoing and the related estimated remediation costs are subject to further change. The Company believes the total PCB remediation costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems. 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. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Distribution Segment Environmental Matters.

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. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

North Attleborough 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. The Company, working with the MADEP, is in the process of performing assessment work at these properties. In a September 2006 report filed with MADEP, the Company proposed a remedy for the upland portion of the North Attleboro Site by means of an engineered barrier. Construction of this remedy was completed in October 2008. Assessment activities continue at the remaining areas on-site and at the off-site properties. It is estimated that the Company will spend approximately $7.1 million over the next several years to complete the investigation and remediation activities at the North Attleboro Site, as well as maintain the engineered barrier. As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with the North Attleboro Site have been included in Regulatory assets in the Condensed Consolidated Balance Sheet.

Litigation

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, some of which involve substantial amounts. Where appropriate, the Company has made accruals in order to provide for such matters. The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Bay Street, Tiverton, Rhode Island Site. In March 2003, RIDEM sent the Company’s New England Gas Company division a letter of responsibility pertaining to soils allegedly impacted by historic MGP residuals in a residential neighborhood in Tiverton, Rhode Island. Without admitting responsibility or accepting liability, New England Gas Company began assessment work in June 2003. In September 2006, RIDEM filed an Amended Notice of Violation seeking an administrative penalty of $1,000/day, which as of the date of RIDEM’s filing totaled $258,000. In April 2007, the Company filed a complaint, and an accompanying preliminary injunction motion, against RIDEM in Rhode Island Superior Court, seeking, among other things, a declaratory judgment that RIDEM's Amended Notice of Violation is premised on an unlawful application of RIDEM's regulations and that RIDEM's pending administrative proceeding against the Company is invalid. In July 2007, the Superior Court dismissed the Company’s suit, finding that RIDEM’s Administrative Adjudication Division (AAD) has original jurisdiction to determine “responsible party” status and finding premature the Company’s challenge to RIDEM’s unlawful application of its own regulations because the Company did not first seek a ruling on that issue through RIDEM’s AAD. The Company has appealed from part of the Superior Court’s ruling and has also filed a motion for summary judgment in the AAD proceeding seeking dismissal thereof based on RIDEM’s unlawful application of its own regulations.

During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood. These lawsuits were consolidated for trial. The plaintiffs seek to recover damages for the diminution in value of their property, lost use and enjoyment of their property and emotional distress in an unspecified amount. The Company removed the lawsuits to federal court and filed motions to dismiss. In November 2006, the Court dismissed plaintiffs’ claims relating to gross negligence, private nuisance, infliction of emotional distress and violation of the Rhode Island Hazardous Waste Management Act. The Court denied the Company’s motion to dismiss as to claims relating to negligence, strict liability and public nuisance, as well as plaintiffs’ request for punitive damages. In September and October 2007, the court granted the Company’s motion to serve third-party complaints on a total of nine PRPs. Among the PRPs the Company impleaded is the Town of Tiverton, which asserted a counterclaim against the Company under the Comprehensive Environmental Response, Compensation, and Liability Act. In January 2008, the Court denied the Company's motion for partial judgment on the pleadings seeking dismissal of plaintiffs' claims for remediation, finding, contrary to the Company's contention, that RIDEM does not have exclusive jurisdiction to determine the responsibility for and extent of remediation of plaintiffs' properties. The trial, which was scheduled to commence on April 28, 2008, was adjourned without date by the Court in consideration of the progress of settlement discussions between the Company and the plaintiffs.

In May 2009, a settlement was reached that resolves all claims between all plaintiffs and the Company and all claims between the Town of Tiverton and the Company in the civil litigation, and also resolves the administrative proceeding with RIDEM. Under the terms of the settlement, the Company will at closing pay $11.5 million to the plaintiffs, who will be responsible for any necessary remediation of the Bay Street area. The closing pursuant to the settlement will take place following plaintiffs' satisfaction of certain conditions.

Mercury Release. In October 2004, New England Gas Company discovered that one of its facilities had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. In October 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island alleging violation of permitting requirements under the federal RCRA and notification requirements under the federal Emergency Planning and Community Right to Know Act (EPCRA) relating to the 2004 incident. The Company entered a not guilty plea on October 29, 2007 and trial commenced on September 22, 2008. On October 15, 2008, the jury acquitted Southern Union on the EPCRA count and one of the two RCRA counts and found the Company guilty on the other RCRA count. On July 23, 2009, the Court denied the Company's motion for acquittal and alternatively for a new trial with respect to the sole count on which the Company was found guilty. The Court has set October 2, 2009 as the date for sentencing. The Company intends to appeal the conviction. The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Multiple civil complaints were filed against the Company in various courts in Providence, Rhode Island regarding the mercury release. Settlements with regard to these civil suits have been reached in an amount less than $300,000.

Jack Grynberg. Jack Grynberg, an individual, filed actions for damages against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Among the defendants are Panhandle, Citrus, Florida Gas and certain of their affiliates (Company Defendants). On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the Company Defendants. Grynberg is appealing that action to the Tenth Circuit Court of Appeals. Grynberg’s opening brief was filed on July 31, 2007. Respondents filed their brief rebutting Grynberg’s arguments on November 21, 2007. A hearing before the Court of Appeals was held on September 25, 2008 and on March 17, 2009, the court denied Grynberg’s appeal. On May 4, 2009, the Court denied Grynberg’s petition for rehearing. On August 4, 2009, Grynberg appealed the Court of Appeals decision to the United States Supreme Court. A similar action, known as the Will Price litigation, also has been filed against a number of companies, including Panhandle, in U.S. District Court for the District of Kansas. Panhandle is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action. Panhandle and the other Company Defendants believe that their measurement practices conformed to the terms of their FERC gas tariffs, which were filed with and approved by FERC. As a result, the Company believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle and the other Company Defendants complied with the terms of their tariffs) and will continue to vigorously defend against them, including any appeal from the dismissal of the Grynberg case. The Company does not believe the outcome of these cases will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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 is seeking recovery of each contractor’s share of approximately $50 million of cost overruns from the construction contractor, multiple inspection contractors and the construction management contractor for improper welding, inspection and construction management of the East End Project. Certain of the contractors have filed counterclaims against PEPL for alleged underpayment of approximately $18 million. The matter is pending in state court in Harris County, Texas. Trial is set for February 2010. The Company does not believe the outcome of this case will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Southwest Gas Litigation. Appeals have been completed in an action in the U.S. District Court for the District of Arizona in which the jury awarded the Company nearly $400,000 in actual damages, and, after reduction on appeal, approximately $1.2 million in punitive damages, along with costs of approximately $100,000 and interest. The award is the result of a trial, which was concluded in December 2002, at which the Company pursued claims against former Arizona Corporation Commissioner James Irvin, regarding his conduct during certain competing efforts to acquire Southwest Gas Corporation. The Company anticipates receipt during the third quarter of approximately $1 million of the award from funds subject to court order as partial security for the judgment. The Company intends to continue to vigorously pursue collection against former Commissioner Irvin for the remaining balance. There can be no assurance, however, as to the amount of such additional damages, if any, that the Company ultimately will collect.

Other Commitments and Contingencies

Retirement of Debt Obligations. The Company repaid its $60.6 million 6.50% Senior Notes, which matured in July 2009, using a portion of the proceeds from the $150 million 8.125% Senior Notes. The Company also prepaid the $150 million Short-Term Facility in July 2009 using borrowings under its Credit Facilities, in anticipation of closing on the 2009 Term Loan, which occurred on August 5, 2009. The Company has $100 million 6.089% Senior Notes maturing in February 2010 and $40.5 million 8.25% Senior Notes maturing in April 2010, which the Company may choose to retire upon maturity by utilizing some combination of cash flows from operations, draw downs under existing Credit Facilities and altering the timing of controllable cash flows, among other things. The Company believes that it will have sufficient liquidity under its Credit Facilities to redeem the total $140.5 million of debt coming due in 2010.

2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Damage from the hurricanes has affected both the Company’s Transportation and Storage and Gathering and Processing segments. Offshore transportation facilities, including Sea Robin and Trunkline’s Terrebonne system, suffered damage to several platforms and gathering pipelines, and Sea Robin is continuing to experience reduced volumes as not all of its damaged facilities are back in service. In late July 2009, during testing to put the remaining offshore facilities back in service, Sea Robin experienced a pipeline rupture in an area where the pipeline had previously been displaced during Hurricane Ike and subsequently re-buried. The SUGS business was indirectly adversely affected by Hurricane Ike.

The Company increased its provision for repair and abandonment costs in 2009 by approximately $16.1 million. The incremental 2009 expense is primarily due to an increase in the provision for repair costs of $9.2 million and $6.9 million of expense related to an increase in the ARO liability reserve. The capital replacement and retirement expenditures relating to the hurricanes, including preliminary estimates for the additional pipe replacement required related to the rupture, has been increased during 2009 to approximately $180 million and is expected to be incurred through 2010. These estimates are subject to further revision as the assessment of the damage to the Company’s facilities is ongoing. Approximately $64 million of the capital replacement and retirement expenditures were incurred as of June 30, 2009. The Company anticipates reimbursement from its property insurance carrier for a significant portion of the damages in excess of its $10 million deductible; however, the recoverable amount is subject to pro rata reduction to the extent that the level of total accepted claims from all insureds exceeds the carrier’s $750 million aggregate exposure limit. The Company’s insurance provider has announced that it has reached the $750 million aggregate exposure limit and has recently revised its estimated payout amount from 70 percent to 63 percent based on estimated claim information it has received. The final amount of any applicable pro rata reduction cannot be determined until the Company’s insurance provider has received and assessed all claims. Receivables due from the insurance carrier of approximately $20 million have been recorded as of June 30, 2009 for submitted Hurricane Ike claims approved for payout by the carrier.

13. Reportable Segments

The Company’s reportable business segments are organized based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses, as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

The remainder of the Company’s business operations, which do not meet the quantitative threshold for segment reporting, are presented as Corporate and other. Corporate and other consists 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, 2009 and 2008.

The following table sets forth certain selected financial information for the Company’s segments for the periods presented.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Segment Data	2009		2008			2009		2008
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	172,615	$	168,333		$	364,910	$	355,384
Gathering and Processing		175,084		440,323			343,389		855,985
Distribution		104,532		122,922			426,556		471,557
Total segment operating revenues		452,231		731,578			1,134,855		1,682,926
Corporate and other		794		1,477			2,033		2,827
Total consolidated revenues from external
customers	$	453,025	$	733,055		$	1,136,888	$	1,685,753

Depreciation and amortization:
Transportation and Storage	$	28,483	$	25,691		$	56,346	$	50,752
Gathering and Processing		16,543		15,346			32,956		30,816
Distribution		7,808		7,722			15,479		15,294
Total segment depreciation and amortization		52,834		48,759			104,781		96,862
Corporate and other		526		562			1,049		1,082
Total depreciation and amortization expense	$	53,360	$	49,321		$	105,830	$	97,944

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	21,984	$	21,572		$	37,768	$	37,814
Gathering and Processing		498		(584	)		1,026		(266	)
Corporate and other		212		110			473		279
	$	22,694	$	21,098		$	39,267	$	37,827

Segment performance:
Transportation and Storage EBIT (1)	$	97,922		$	98,526	$	191,144		$	212,626
Gathering and Processing EBIT		(1,523	)		12,134		(12,956	)		40,690
Distribution EBIT (1)		(291	)		928		31,347			29,410
Total segment EBIT		96,108			111,588		209,535			282,726
Corporate and other (1)		(628	)		507		187			(9	)
Interest expense		48,365			50,603		96,735			101,304
Federal and state income tax expense		13,835			18,582		33,450			55,595
Net earnings		33,280			42,910		79,537			125,818
Preferred stock dividends		2,170			3,436		4,341			7,777
Loss on extinguishment of preferred stock		-			1,995		-			1,995
Net earnings available for common stockholders	$	31,110		$	37,479	$	75,196		$	116,046

__________________

(1)

In the fourth quarter of 2008, the Company ceased including the management and royalty fees charged by Southern Union to its Transportation and Storage segment in its evaluation of segment results as it was no longer deemed necessary by executive management. The Company had not previously included management and royalty fees in the evaluation of its other reportable segments. Additionally, in the fourth quarter of 2008, the Company commenced allocating certain corporate administrative services costs to the Distribution segment. Previously, the corporate administrative services costs allocation was limited to the Transportation and Storage and Gathering and Processing segments. Executive management determined that such allocation to all of the Company's reportable segments would enable it to better measure and evaluate the performance of each of its reportable segments. The allocations to the Distribution segment for the three- and six- month periods ended June 30, 2009 were $2.5 million and $4.8 million, respectively. The administrative services allocation was primarily based upon each reportable segment's pro-rata share of combined net investment, margin and certain expenses. Management believes that the allocation method and underlying assumptions utilized by the Company were reasonable.

For purposes of comparability between reporting periods, the 2008 period has been recast as indicated below to (i) exclude the management and royalty fee charged to the Transportation and Storage segment, and (ii) include the corporate administrative services allocation to the Distribution segment.

	Three Months Ended June 30, 2008
	Recast Adjustments
Segment Impacted	EBIT as Reported		Increase (Decrease)				Recast EBIT
				(In thousands)

Transportation and Storage	$	94,313		$	4,213		$	98,526
Distribution		2,819			(1,891	)		928
Corporate and Other		2,829			(2,322	)		507


	Six Months Ended June 30, 2008
	Recast Adjustments
Segment Impacted	EBIT as Reported		Increase (Decrease)				Recast EBIT
				(In thousands)

Transportation and Storage	$	203,694		$	8,932		$	212,626
Distribution		33,120			(3,710	)		29,410
Corporate and Other		5,213			(5,222	)		(9	)

	June 30,		December 31,
Segment Data	2009		2008
	(In thousands)
Total assets:
Transportation and Storage	$	4,997,965	$	4,969,336
Gathering and Processing		1,651,899		1,764,497
Distribution		1,034,002		1,177,124
Total segment assets		7,683,866		7,910,957
Corporate and other		118,086		86,950
Total consolidated assets	$	7,801,952	$	7,997,907


	Three Months Ended				Six Months Ended
	June 30,				June 30,
		2009		2008		2009		2008
	(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	52,176	$	90,663	$	129,888	$	272,829
Gathering and Processing		5,300		15,310		16,518		32,779
Distribution		16,706		11,004		23,268		16,708
Total segment expenditures for
long-lived assets		74,182		116,977		169,674		322,316
Corporate and other		10,087		536		17,003		1,756
Total consolidated expenditures for
long-lived assets (1)	$	84,269	$	117,513	$	186,677	$	324,072

_______________________

(1)

Includes net period changes in capital accruals totaling $10.4 million and $(5.5) million for the three-month periods ended June 30, 2009 and 2008, respectively. Includes net period changes in capital accruals totaling $20.3 million and $16.3 million for the six-month periods ended June 30, 2009 and 2008, respectively.

14. Regulation and Rates

Panhandle. The Company commenced construction of an enhancement at its Trunkline LNG terminal in February 2007. This infrastructure enhancement project, which is expected to be placed in operation in the third quarter of 2009, will increase send out flexibility at the terminal and lower fuel costs for the customer. Cost projections continue to indicate the construction costs will be approximately $430 million, plus capitalized interest. Approximately $420.9 million and $351.3 million of costs, including capitalized interest, are included in the line item Construction work-in-progress at June 30, 2009 and December 31, 2008, respectively.

Missouri Gas Energy. On April 2, 2009, Missouri Gas Energy made a filing with the MPSC seeking to implement an annual base rate increase of approximately $32.4 million. Approved rates resulting from this filing are not expected to take effect until February 28, 2010.

On July 1, 2008, the Circuit Court of Greene County, Missouri made a docket entry indicating that, following judicial review, it had affirmed the Report and Order issued by the MPSC resolving Missouri Gas Energy’s general rate increase that went into effect on April 3, 2007. While that judicial review proceeding has been appealed to the Southern District of the Missouri Court of Appeals by both Missouri Gas Energy and the Office of the Public Counsel, the Company does not believe the outcome of the judicial review will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

New England Gas Company. On September 15, 2008, New England Gas Company made a filing with the MDPU seeking recovery of approximately $4 million, or 50 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 in its entirety. The Company appealed that decision to the Massachusetts Supreme Judicial Court on February 17, 2009.

15. Stockholders’ Equity

Dividends. The table below presents the amount of cash dividends declared and paid on the dates indicated:

Shareholder Record Date	Date Paid	Amount Per Share		Amount Paid
				(In thousands)

June 26, 2009	July 10, 2009	$	0.15	$	18,607
March 27, 2009	April 10, 2009		0.15		18,607

16. Other Income (Expense), Net

Other, net income for the six-month period ended June 30, 2009 totaling $6.1 million consists primarily of $5.7 million related to an insurance settlement. During 2009, the Company entered into a settlement agreement with an insurance company releasing the insurance company from certain potential future environmental claim obligations.

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 Southern Union’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 to anticipate 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, quantitative and qualitative disclosures about market risk and other matters.

OVERVIEW

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 executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution.

RESULTS OF OPERATIONS

Overview

The Company evaluates operational and financial segment performance using several factors, of which the primary financial measure is EBIT, which is 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.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
	(In thousands)
EBIT:
Transportation and storage segment (1)	$	97,922		$	98,526	$	191,144		$	212,626
Gathering and processing segment		(1,523	)		12,134		(12,956	)		40,690
Distribution segment (1)		(291	)		928		31,347			29,410
Corporate and other (1)		(628	)		507		187			(9	)
Total EBIT		95,480			112,095		209,722			282,717
Interest		48,365			50,603		96,735			101,304
Earnings before income taxes		47,115			61,492		112,987			181,413
Federal and state income tax expense		13,835			18,582		33,450			55,595
Net earnings		33,280			42,910		79,537			125,818
Preferred stock dividends		2,170			3,436		4,341			7,777
Loss on extinguishment of preferred stock		-			1,995		-			1,995

Net earnings available for common stockholders	$	31,110		$	37,479	$	75,196		$	116,046

_________________

(1)	The amounts reported for the 2008 periods have been recasted. See Part 1, Item 1. Financial Information (Unaudited), Note 13 – Reportable Segments for information related to the recasted amounts.

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The Company’s $6.4 million decrease in Net earnings available for common stockholders in the three-month period ended June 30, 2009 versus the same period in 2008 was primarily due to:

Lower EBIT contributions of $13.7 million from the Gathering and Processing segment primarily due to lower operating revenues of $294.8 million, largely attributable to lower market-driven realized average natural gas and NGL prices, partially offset by the impact of $29.6 million of lower net hedging losses and lower market-driven natural gas and NGL purchase costs of $248 million in the 2009 period versus the 2008 period;

·	Lower EBIT contribution of $1.2 million from the Distribution segment primarily due to higher property tax assessments of $900,000 associated with natural gas inventory stored in the state of Kansas, which became assessable for property tax purposes beginning in 2009; and

·	Lower EBIT contributions of $1.1 million from the Corporate and other segment primarily due to lower revenues of $700,000 from PEI Power Corporation attributable to lower electricity prices in 2009 and a scheduled maintenance outage.

These reductions in earnings were partially offset by:

Lower interest expense of $2.2 million primarily attributable to lower interest expense of $2.3 million due to lower LIBOR interest rates associated with the Company’s variable rate debt and the impact of $2 million of the higher level of interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008, partially offset by higher net interest expense of $2.1 million due to higher net debt balances outstanding on fixed-rate debt obligations;

Impact of a $2 million loss recorded in the 2008 period related to the Company’s purchase of 191,884 shares of its 7.55% Noncumulative Preferred Stock, Series A shares (Preferred Stock) and the reduction in related dividends of $1.3 million in the 2009 period versus the 2008 period associated with the Company’s purchase of 459,999 total shares of Preferred Stock during 2008; and

Lower federal and state income tax expense of $4.7 million primarily due to lower pre-tax earnings of $14.4 million and the impact of the reduced EITR attributable to a lower state income tax expense (net of the federal income tax benefit) of $800,000 and an increase in the tax benefit (relative to lower pre-tax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The Company’s $40.9 million decrease in Net earnings available for common stockholders in the six-month period ended June 30, 2009 versus the same period in 2008 was primarily due to:

Lower EBIT contributions of $53.6 million from the Gathering and Processing segment primarily due to lower operating revenues of $528.2 million, largely attributable to lower market-driven realized average natural gas and NGL prices, partially offset by the impact of $15.6 million of lower net hedging losses and lower market-driven natural gas and NGL purchase costs of $455 million in the 2009 period versus the 2008 period; and

Lower EBIT contributions of $21.5 million from the Transportation and Storage segment primarily due to higher operating expenses of $23.8 million attributable to a net increase in the provision for repair and abandonment costs of $16.1 million in 2009 related to offshore assets damaged by Hurricane Ike, higher contract storage costs of $1.9 million, higher fuel tracker costs of $3.4 million primarily due to a net over-recovery in 2008 versus a net under-recovery in 2009, a $2.3 million increase in LNG power expense resulting from actual costs recovered in rates through the power reimbursement mechanism and higher depreciation and amortization expense of $5.6 million primarily due to increases in property, plant and equipment, partially offset by higher operating revenues of $9.5 million attributable to higher transportation and storage revenues of $6.2 million primarily attributable to higher average rates realized by PEPL and contributions from various expansion projects and higher LNG terminalling revenues of $4.7 million.

These reductions in earnings were partially offset by:

Higher EBIT contributions of $1.9 million from the Distribution segment primarily due to the impact of $3.5 million of income in 2009 related to a settlement agreement with an insurance company releasing the insurance company from certain potential future environmental claim obligations, partially offset by higher property tax assessments of $900,000 associated with natural gas inventory stored in the state of Kansas, which became assessable for property tax purposes beginning in 2009;

Lower interest expense of $4.6 million primarily attributable to lower interest expense of $5.9 million due to lower LIBOR interest rates associated with the Company’s variable rate debt and the impact of $2.9 million of the higher level of interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008, partially offset by higher net interest expense of $3.8 million due to higher net debt balances outstanding on fixed-rate debt obligations;

Impact of a $2 million loss recorded in the 2008 period related to the Company’s purchase of 191,884 shares of its Preferred Stock and the reduction in related dividends of $3.4 million in the 2009 period versus the 2008 period associated with the Company’s purchase of 459,999 total shares of Preferred Stock during 2008; and

Lower federal and state income tax expense of $22.1 million primarily due to lower pre-tax earnings of $68.4 million and the impact of the reduced EITR attributable to a lower state income tax expense (net of the federal income tax benefit) of $2.5 million and an increase in the tax benefit (relative to lower pre-tax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus.

Business Segment Results

Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest 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 on Panhandle’s pipeline systems is seasonal, with the highest throughput and a higher portion of annual total operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. Florida Gas’ pipeline system experiences the highest throughput in the summer period due to gas-fired generation loads in the second and third calendar quarters.

The Company’s business within the Transportation and Storage segment is conducted through both short- and long-term contracts with customers. Shorter-term contracts, which can increase the volatility of revenues, are driven by changes in market conditions and competition with other pipelines, changing supply sources and volatility in natural gas prices. Since the majority of the revenues within the Transportation and Storage segment are related to firm capacity reservation charges, changes in commodity prices and 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 commodity prices and volumes transported. Over the past several years, the weighted average life of contracts has actually trended somewhat higher as customers have exhibited an increased focus in securing longer-term supply and related transport capacity from the supply and market areas served by the Company.

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Transportation and Storage Segment	2009		2008		2009		2008
	(In thousands)

Operating revenues	$	172,615	$	168,333	$	364,910	$	355,384

Operating expenses		59,981		58,448		138,175		114,421
Depreciation and amortization		28,483		25,691		56,346		50,752
Taxes other than on income and revenues		8,313		7,544		17,238		16,193
Total operating income		75,838		76,650		153,151		174,018
Earnings from unconsolidated investments		21,984		21,572		37,768		37,814
Other income, net		100		304		225		794
EBIT	$	97,922	$	98,526	$	191,144	$	212,626

Operating information:
Panhandle natural gas volumes transported (TBtu)		376		328		803		729
Florida Gas natural gas volumes transported (TBtu) (1)		216		211		403		384

________________

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

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The $600,000 EBIT reduction in the three-month period ended June 30, 2009 versus the same period in 2008 was primarily due to a lower EBIT contribution from Panhandle totaling $1 million, offset by higher equity earnings of $400,000, principally from the Company’s unconsolidated investment in Citrus.

Panhandle’s $1 million EBIT reduction was primarily due to:

·	Higher operating revenues of $4.3 million primarily attributable to:

o	Higher transportation reservation revenues of $5.4 million primarily due to higher average rates realized on PEPL and contributions from various expansion projects, partially offset by the impact of lower average rates on Trunkline;

A $2.5 million increase in LNG terminalling revenue primarily due to $1.2 million associated with a change in the power reimbursement mechanism in the fourth quarter of 2008 that allows the Company to recover actual monthly LNG electric power costs from the customer and approximately $1.4 million of higher reservation revenues attributable to a one-time annual rate increase associated with certain capacity effective January 1, 2009; and

o	Lower transportation usage revenues of $3.4 million primarily due to reduced volumes flowing after Hurricane Ike.

The increased revenues were offset by:

·	Higher operating expenses of $1.5 million primarily attributable to:

o	A $2.8 million increase in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2009;

o	A $1.3 million increase in third-party transportation expense primarily due to additional capacity contracted;

o	A $1.2 million increase in LNG power expense resulting from actual costs recovered in rates through the power reimbursement mechanism; and

o	A $3.2 million decrease in outside services costs related to field operations primarily attributable to the timing of ongoing pipeline integrity testing costs and other reductions to pipeline system operating and maintenance costs; and

Increased depreciation and amortization expense of $2.8 million due to a $216 million increase in property, plant and equipment placed in service after June 30, 2008. Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, primarily from the LNG terminal infrastructure enhancement construction project.

Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were higher by $400,000 in 2009 versus 2008 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

·	Higher other income of $5.9 million primarily due to higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project;

·	Higher transportation revenues of $900,000 primarily due to higher reservation revenue attributable to additional phased-in capacity contracted resulting from Florida Gas’ Phase VII Expansion project;

Higher debt interest cost of $4.7 million primarily due to interest on a $500 million construction and term loan agreement funded in October 2008 and on the $600 million 7.90% Senior Notes issued in May 2009, partially offset by lower average outstanding revolver debt balances and lower LIBOR interest rates;

·	Higher operating expenses of $1.3 million primarily due to higher overall costs experienced in 2009 applicable to outside service costs, employee labor, and other operating costs; and

·	Higher depreciation expense of $300,000 primarily due to increased property, plant and equipment placed in service after June 30, 2008.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The $21.5 million EBIT reduction in the six-month period ended June 30, 2009 versus the same period in 2008 was primarily due to a lower EBIT contribution from Panhandle totaling $21.4 million and lower equity earnings of $46,000, principally from the Company’s unconsolidated investment in Citrus.

Panhandle’s $21.4 million EBIT reduction was primarily due to:

·	Higher operating revenues of $9.5 million primarily attributable to:

Higher transportation reservation revenues of $7.7 million primarily due to higher average rates realized on PEPL, contributions from various expansion projects, primarily consisting of the Trunkline Field Zone Expansion and PEPL East End Enhancement projects, partially offset by the impact of approximately $1.2 million of additional revenues in the 2008 period attributable to the extra day in the 2008 leap year and lower average rates realized on Trunkline;

o	Higher parking revenues of $5 million resulting from customer demand for parking services and market conditions;

A $4.7 million increase in LNG terminalling revenue primarily due to $2.4 million associated with a change in the power reimbursement mechanism in the fourth quarter of 2008 that allows the Company to recover actual monthly LNG electric power costs from the customer and approximately $2.3 million of higher reservation revenues attributable to a one-time annual rate increase associated with certain capacity effective January 1, 2009; and

o	Lower transportation usage revenues of $7.4 million primarily due to reduced volumes flowing after Hurricane Ike.

The increased revenues were offset by:

·	Higher operating expenses of $23.8 million primarily attributable to:

o	A net increase in the provision for repair and abandonment costs of $16.1 million in 2009 for damages to offshore assets resulting from Hurricane Ike, which is generally expected to be recovered in the future through insurance recoveries and new rate proceedings;

o	A $3.4 million increase in fuel tracker costs primarily due to a net over-recovery in 2008 versus a net under-recovery in 2009;

o	A $2.3 million increase in LNG power expense resulting from actual costs recovered in rates through the power reimbursement mechanism;

o	A $1.9 million increase in contract storage costs resulting from an increase in leased storage capacity;

o	A $1.9 million increase in third-party transportation expense primarily due to additional capacity contracted; and

o	A $1.3 million decrease in property insurance premiums; and

Increased depreciation and amortization expense of $5.6 million due to a $216 million increase in property, plant and equipment placed in service after June 30, 2008. Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, primarily from the LNG terminal infrastructure enhancement construction project.

See Part I, Item 1. Financial Statements (Unaudited), Note 12 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional information related to the 2009 increases in the repair and abandonment provisions and insurance recovery resulting from hurricane damage.

Equity earnings, primarily attributable to the Company’s unconsolidated investment in Citrus, were lower by $46,000 in 2009 versus 2008 primarily due to the following items, adjusted where applicable to reflect the Company’s proportional equity share:

Higher debt interest cost of $7.4 million primarily due to interest on a $500 million construction and term loan agreement funded in October 2008 and on the $600 million 7.90% Senior Notes issued in May 2009, partially offset by lower average outstanding revolver debt balances and lower LIBOR interest rates;

·	Higher operating expenses of $1.7 million primarily due to higher overall costs experienced in 2009 applicable to outside service costs, employee labor, and other operating costs;

·	Higher depreciation expense of $1 million primarily due to increased property, plant and equipment placed in service after June 30, 2008; and

·	Higher other income of $10 million primarily due to higher equity AFUDC resulting from Florida Gas’ Phase VIII Expansion project.

See Part I, Item I. Financial Statements (Unaudited), Note 5 – Unconsolidated Investments – Citrus for additional information related to Florida Gas.

Gathering and Processing Segment. 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 conducted through SUGS. SUGS’ gas supply contracts primarily include fee-based, percent-of-proceeds, conditioning fee and wellhead purchase contracts. These 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 producers, power generating companies, utilities, energy marketers, and industrial end-users located primarily in the Gulf Coast and southwestern United States. SUGS’ business is not generally seasonal in nature.

The majority of SUGS’ gross margin is derived from the sale of NGL equity volumes and to a lesser extent from the sale of residue natural gas. 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 I. Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment and Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

The following table presents the results of operations applicable to the Company’s Gathering and Processing segment:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Gathering and Processing Segment	2009			2008			2009			2008
	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	177,624		$	472,423		$	356,001		$	884,219
Realized and unrealized commodity derivatives		(2,540	)		(32,100	)		(12,612	)		(28,234	)
Operating revenues		175,084			440,323			343,389			855,985
Cost of gas and other energy (1)		(141,269	)		(390,339	)		(284,398	)		(738,539	)
Gross margin (2)		33,815			49,984			58,991			117,446
Operating expenses		18,123			20,189			37,785			43,138
Depreciation and amortization		16,543			15,346			32,956			30,816
Taxes other than on income and revenues		1,166			1,718			2,506			2,519
Total operating income		(2,017	)		12,731			(14,256	)		40,973
Earnings from unconsolidated investments		498			(584	)		1,026			(266	)
Other expense, net		(4	)		(13	)		274			(17	)
EBIT	$	(1,523	)	$	12,134		$	(12,956	)	$	40,690


Operating information:
Volumes
Avg natural gas processed (MMBtu/d)		407,777			433,568			414,304			420,825
Avg NGL produced (gallons/d)		1,394,504			1,428,903			1,382,674			1,382,468
Avg natural gas wellhead (MMBtu/d)		600,358			624,259			589,518			623,704
Natural gas sales (MMBtu)		23,671,746			23,666,144			45,228,917			47,825,389
NGL sales (gallons) (3)		144,398,030			145,598,927			310,489,377			300,259,328

Average Pricing
Realized natural gas ($/MMBtu) (4)	$	3.06		$	9.86		$	3.27		$	8.81
Realized composite NGL ($/gallon) (4)		0.71			1.62			0.65			1.51
Natural Gas Daily WAHA ($/MMBtu)		3.11			10.10			3.26			9.05
Natural Gas Daily El Paso ($/MMBtu)		3.02			9.90			3.17			8.91
Estimated plant processing spread ($/gallon)		0.41			0.70			0.35			0.69

________________

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

(2)	Gross margin consists of Operating revenues less Cost of gas and other energy. The Company believes that this measurement 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 periods ended June 30, 2009 and 2008, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $9.8 million and $31.9 million, and 3,088,000 million MMBtus and 3,150,000 million MMBtus, respectively. The Company’s operating revenues and related volumes for the three-month periods ended June 30, 2009 and 2008 attributable to its buy-sell arrangements for NGL totaled $14.6 million and $30.3 million, and 22,280,000 million gallons and 19,848,000 million gallons, respectively. For the six-month periods ended June 30, 2009 and 2008, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $21.5 million and $60.8 million, and 6,344,000 million MMBtus and 6,731,000 million MMBtus, respectively. The Company’s operating revenues and related volumes for the six-month periods ended June 30, 2009 and 2008 attributable to its buy-sell arrangements for NGL totaled $26.5 million and $77.8 million, and 43,114,000 million gallons and 54,325,000 million gallons, respectively.

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

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The $13.7 million EBIT reduction in the three-month period ended June 30, 2009 versus the same period in 2008 was primarily due to the following items:

·	Lower gross margin of $16.2 million primarily as the result of:

Lower operating revenues of $294.8 million largely attributable to lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.06 per MMBtu and $0.71 per gallon in the 2009 period versus $9.86 per MMBtu and $1.62 per gallon in the 2008 period, respectively;

o	Impact of lower market driven natural gas and NGL purchase costs of $248 million in the 2009 period versus the 2008 period; and

o	Impact of $29.6 million of lower net hedging losses in the 2009 period versus the 2008 period (which includes the impact of $5.5 million of unrealized losses recorded in 2009);

·	Higher depreciation and amortization expense of $1.2 million primarily attributable to a $64 million increase in property, plant and equipment placed in service after June 30, 2008;

·	Lower operating expenses of $2.1 million primarily due to:

o	A $1.2 million decrease in maintenance, contract services costs and other plant operating costs largely attributable to a 2009 cost reduction initiative primarily related to the Company’s variable and discretionary costs;

o	A $600,000 decrease in utilities costs primarily due to lower compressor fuel costs attributable to the associated declining costs of natural gas in 2009 versus 2008; and

o	A $200,000 decrease in chemical and lubricants costs, which generally track with the price of oil; and

·	Higher equity earnings of $1.1 million from the Company’s unconsolidated investment in Grey Ranch primarily due to higher volumes in 2009 versus the 2008 period resulting from an increase in capacity from 90 MMcf/d to 200 MMcf/d effective December 31, 2008.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The $53.6 million EBIT reduction in the six-month period ended June 30, 2009 versus the same period in 2008 was primarily due to the following items:

·	Lower gross margin of $58.5 million primarily as the result of:

Lower operating revenues of $528.2 million largely attributable to lower market-driven realized average natural gas and NGL prices (unadjusted for the impact of realized and unrealized commodity derivative gains and losses) of $3.27 per MMBtu and $0.65 per gallon in the 2009 period versus $8.81 per MMBtu and $1.51 per gallon in the 2008 period, respectively;

o	Impact of lower market-driven natural gas and NGL purchase costs of $455 million in the 2009 period versus the 2008 period; and

o	Impact of $15.6 million of lower net hedging losses in the 2009 period versus the 2008 period (which includes the impact of $20.7 million of unrealized losses recorded in 2009);

·	Higher depreciation and amortization expense of $2.1 million primarily attributable to a $64 million increase in property, plant and equipment placed in service after June 30, 2008;

·	Lower operating expenses of $5.4 million primarily due to:

o	A $2.1 million decrease in maintenance, contract services and other plant operating costs largely attributable to a 2009 cost reduction initiative primarily related to the Company’s variable and discretionary costs;

o	A $1 million decrease in utilities costs primarily due to lower compressor fuel costs attributable to the associated declining costs of natural gas in 2009 versus 2008;

o	A $700,000 decrease in chemical and lubricants costs, which generally track with the price of oil; and

o	Lower corporate services costs of $600,000; and

·	Higher equity earnings of $1.3 million from the Company’s unconsolidated investment in Grey Ranch primarily due to higher volumes in 2009 versus the 2008 period resulting from an increase in capacity from 90 MMcf/d to 200 MMcf/d effective December 31, 2008.

On July 17, 2009, SUGS experienced a fire at its Keystone natural gas processing plant forcing it to shut in its attendant production for approximately two weeks. SUGS expects to operate at reduced production levels until late in the third quarter of 2009. SUGS has preliminarily estimated the impact of the fire will result in (i) a reduction of its gross margin contribution by $4 million to $5 million, (ii) charges to earnings of $2.5 million to $4 million for the write-off of property and equipment damaged by the fire, and (iii) capital replacement expenditures of $12 million, net of estimated insurance reimbursements.

Distribution Segment. 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 divisions, respectively. The Distribution segment’s operations are regulated as to rates and other matters by the 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 and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 88 percent of its total natural gas sales customers and approximately 69 percent of its gross natural gas sales revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Distribution Segment	2009			2008			2009		2008
	(In thousands)

Net operating revenues (1)	$	49,246		$	48,649		$	117,434	$	116,760

Operating expenses		37,692			36,951			66,921		65,831
Depreciation and amortization		7,808			7,722			15,479		15,294
Taxes other than on income and revenues		3,790			2,655			6,882		5,644
Total operating income (loss)		(44	)		1,321			28,152		29,991
Other income (expenses), net		(247	)		(393	)		3,195		(581	)
EBIT	$	(291	)	$	928		$	31,347	$	29,410

Operating Information:
Gas sales volumes (MMcf)		9,166			10,468			38,806		43,333
Gas transported volumes (MMcf)		5,617			6,052			13,966		15,686

Weather – Degree Days: (2)
Missouri Gas Energy service territories		459			499			2,953		3,420
New England Gas Company service territories		777			777			3,747		4,057

_____________________

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

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

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The $1.2 million reduction of EBIT in the three-month period ended June 30, 2009 versus the same period in 2008 was primarily due to higher taxes other than on income and revenues of $1.1 million largely attributable to $900,000 of property taxes associated with natural gas inventory stored in the state of Kansas, which became assessable for property tax purposes beginning in 2009. The Company expects an impact of $1.8 million in 2009 will result from the new property tax assessments for natural gas stored in the state of Kansas, which amount will vary as the assessment is based upon inventory balances as of each year end.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The $1.9 million EBIT improvement in the six-month period ended June 30, 2009 versus the same period in 2008 was primarily due to:

·	Higher Other Income, net, of $3.8 million primarily due to a settlement of $3.5 million with an insurance company in 2009 releasing the insurance company from certain potential future environmental claim obligations;

Higher net operating revenues of $700,000 primarily due to a higher contribution of $2.5 million from New England Gas Company largely attributable to the impact of new rates associated with the $3.7 million annual rate case increase effective February 3, 2009, offset by $1.8 million of lower net operating revenues at Missouri Gas Energy primarily due to the impact of warmer weather for its non-residential customers;

·	Higher operating expenses of $1.1 million primarily attributable to:

o	Higher injuries and damages claims of $1.9 million primarily due to the impact of an insurance reimbursement of $900,000 received in 2008 and higher ongoing litigation costs;

o	Higher pension costs of $800,000, which are recovered in current rates;

o	Higher provisions for uncollectible customer accounts of approximately $600,000 primarily resulting from the impact of the current depressed economic conditions on some of the Company’s customers; and

o	Lower environmental remediation costs of $2.6 million primarily attributable to the establishment of reserves in 2008 related to completed site investigation evaluations; and

Higher taxes other than on income and revenues of $1.2 million largely attributable to $900,000 of property taxes associated with natural gas inventory stored in the state of Kansas, which became assessable for property tax purposes beginning in 2009. The Company expects an impact of $1.8 million in 2009 will result from the new property tax assessments for natural gas stored in the state of Kansas, which amount will vary as the assessment is based upon inventory balances as of each year end.

Corporate and Other

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The EBIT reduction of $1.1 million was primarily due to:

·	Lower contributions of $500,000 from PEI Power Corporation primarily due to lower revenues of $700,000 attributable to lower electricity prices in 2009 and the impact of a scheduled maintenance outage during May and June 2009; and

·	Lower interest income of $400,000 in the 2009 period versus the 2008 period associated with short-term investments held by the Company.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The EBIT improvement of $200,000 was primarily due to:

·	A settlement of $1.9 million in March 2009 with an insurance company releasing the insurance company from certain potential future environmental claim obligations;

Lower contributions of $1.3 million from PEI Power Corporation primarily due to lower revenues of $800,000 attributable to lower electricity prices in 2009 and the impact of a scheduled maintenance outage during May and June 2009 and a first quarter 2009 increase of $400,000 in a reserve associated with the Company’s obligation to fund the potential shortfall in estimated future incremental tax revenues associated with the financing obtained by certain tax authorities for the development of an industrial complex; and

·	Lower interest income of $500,000 in the 2009 period versus the 2008 period associated with short-term investments held by the Company.

Interest Expense

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. Interest expense was $2.2 million lower in the three-month period ended June 30, 2009 versus the same period in 2008 primarily due to:

·	Lower interest expense of $2.3 million primarily due to the effect of lower LIBOR interest rates and a lower debt balance on the $465 million term loan agreement;

·	Lower interest expense of $2 million primarily due to the impact of the higher level of interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008; and

Higher net interest expense of $2.1 million primarily due to higher outstanding average debt balances from the $400 million 7.00% Senior Notes issued in June 2008, the $150 million 8.125% Senior Notes issued in June 2009 and the $150 million Short-Term Facility funded in October 2008, partially offset by lower interest expense resulting from the repayment of the $300 million 4.80% Senior Notes and the $125 million 6.15% Senior Notes in August 2008.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. Interest expense was $4.6 million lower in the six-month period ended June 30, 2009 versus the same period in 2008 primarily due to:

·	Lower interest expense of $5.9 million primarily due to the effect of lower LIBOR interest rates and a lower debt balance on the $465 million term loan agreement;

·	Lower interest expense of $2.9 million primarily due to the impact of the higher level of interest costs capitalized attributable to higher average capital project balances outstanding in 2009 compared to 2008; and

Higher net interest expense of $3.8 million primarily due to higher outstanding average debt balances from the $400 million 7.00% Senior Notes issued in June 2008, the $150 million 8.125% Senior Notes issued in June 2009 and the $150 million Short-Term Facility funded in October 2008, partially offset by lower interest expense resulting from the repayment of the $300 million 4.80% Senior Notes and the $125 million 6.15% Senior Notes in August 2008.

Federal and State Income Taxes

The Company’s income taxes were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(In thousands)

Income tax expense	$	13,835	$	18,582	$	33,450	$	55,595
Effective tax rate		29%		30%		30%		31%

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The $4.7 million reduction of federal and state income tax expense was primarily due to lower pre-tax earnings of $14.4 million and the impact of the lower EITR for the three-month period ended June 30, 2009 versus the same period in 2008. The lower EITR was primarily due to:

·	Lower state income tax expense, net of the federal income tax benefit of $1.4 million and $2.2 million for the three-month periods ended June 30, 2009 and 2008, respectively; and

Increase in the tax benefit (relative to lower pretax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus. For the three-month periods ended June 30, 2009 and 2008, the tax benefit of the dividends received deduction was $4.2 million and $4.8 million, respectively.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The $22.1 million reduction of federal and state income tax expense was primarily due to lower pre-tax earnings of $68.4 million and the impact of the lower EITR for the six-month period ended June 30, 2009 versus the same period in 2008. The lower EITR was primarily due to:

·	Lower state income tax expense, net of the federal income tax benefit of $3 million and $5.5 million for the six-month periods ended June 30, 2009 and 2008, respectively; and

Increase in the tax benefit (relative to lower pretax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus. For the six-month periods ended June 30, 2009 and 2008, the tax benefit of the dividends received deduction was $9.4 million and $13.8 million, respectively.

Preferred Stock Dividends and Loss on Extinguishment of Preferred Stock

Three-month period ended June 30, 2009 versus the three-month period ended June 30, 2008. The $3.3 million reduction of preferred stock dividends and loss on extinguishment of preferred stock for the three-month period ended June 30, 2009 versus the same period in 2008 was due to the impact of the $2 million loss the Company recorded in the 2008 period related to its purchase of 1,918,837 depository shares representing 191,884 shares of its Preferred Stock and the reduction in related dividends of $1.3 million in the 2009 period versus the 2008 period associated with the Company’s purchase of 459,999 total shares of Preferred Stock during 2008.

Six-month period ended June 30, 2009 versus the six-month period ended June 30, 2008. The $5.4 million reduction of preferred stock dividends and loss on extinguishment of preferred stock for the six-month period ended June 30, 2009 versus the same period in 2008 was due to the impact of the loss the Company recorded in the 2008 period related to its purchase of 1,918,837 depository shares representing 191,884 shares of its Preferred Stock and the reduction in related dividends of $3.4 million in the 2009 period versus the 2008 period associated with the Company’s purchase of 459,999 total shares of Preferred Stock during 2008.

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, 2008.

Cash generated from internal operations constitutes the Company’s primary source of liquidity. The Company’s working capital deficit at June 30, 2009 is $372.3 million. This includes $100 million and $40.5 million of other long-term debt maturing in February 2010 and April 2010, respectively, and $150 million of short-term debt repaid in July 2009 using borrowings under the Company’s credit facilities. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various equity offerings and debt capital markets and bank 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.

Financial Sector Exposure

Recent events in the global financial markets have caused the Company to place increased scrutiny on its liquidity position and the financial condition of its critical third-party business partners, including the Company’s short-term debt and revolving credit facilities, future capital needs (including long-term borrowing needs and potential refinancing plans) and its joint ventures, derivative counterparties and customer and other contractual relationships. The Company uses publicly available information to assess the potential impact of the current credit markets and related liquidity issues on its business partners and to assess the associated business risks to the Company.

The Company notes that, while it cannot predict the extent or duration of any negative impact that the current credit disruptions in the economy will have on its liquidity position, there is no expectation that the impact on the Company would be significant.

Sources (Uses) of Cash

	Six months ended June 30,
	2009			2008
	(In thousands)
Cash flows provided by (used in):
Operating activities	$	381,825		$	347,344
Investing activities		(230,371	)		(345,542	)
Financing activities		(140,540	)		223,827
Increase (decrease) in cash and cash equivalents	$	10,914		$	225,629

Operating activities. Cash provided by operating activities increased by $34.5 million in the 2009 period versus the same period in 2008. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2009 period was $210 million compared with $306.6 million for the 2008 period, a decrease of $96.6 million primarily resulting from lower net earnings in 2009. Changes in operating assets and liabilities provided cash of $171.8 million in the 2009 period and $40.7 million in the 2008 period, resulting in an increase in cash from changes in operating assets and liabilities of $131.1 million in 2009 compared to 2008. The $131.1 million increase is primarily due to (i) the impact of decreased accounts receivables of $99.1 million in the Distribution and Gathering and Processing segments primarily due to warmer weather for Missouri Gas Energy’s nonresidential customers and the impact of lower commodity prices in 2009 in the Gathering and Processing segment resulting in reduced accounts receivables and (ii) decreased inventory of $74.3 million in the Distribution segment primarily due to decreased natural gas prices in the 2009 period, partially offset by the impact of decreased accounts payables of $89.7 million primarily due to higher natural gas purchase costs in the 2008 period.

Investing activities. The Company’s business strategy includes making prudent capital expenditures across its base of gathering, processing, transmission, storage 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 six months ended June 30, 2009 and June 30, 2008 were $230.4 million and $345.5 million, respectively. The $115.2 million decrease in invested cash outflows is primarily due to a $125.1 million decrease in capital expenditures in the Transportation and Storage segment in the 2009 period.

The following table presents a summary of additions to property, plant and equipment by segment, including additions related to major projects for the periods presented.

	Six Months Ended
	June 30,
Property, Plant and Equipment Additions	2009			2008
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	58,863		$	91,192
Trunkline Field Zone Expansion		941			57,926
East End Enhancement		(56	)		33,999
Compression Modernization		4,887			40,265
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and hurricane
expenditures		65,253			49,447
Total		129,888			272,829

Gathering and Processing Segment		16,518			32,779

Distribution Segment
Missouri Safety Program		6,348			5,159
Other, primarily system replacement
and expansion		16,920			11,549
Total		23,268			16,708

Corporate and other		17,003			1,756

Total (1)	$	186,677		$	324,072

___________________

(1)	Includes net period changes in capital accruals totaling $20.3 million and $16.3 million for the six-month periods ended June 30, 2009 and 2008, respectively.

Principal Capital Expenditure Projects. The Company’s capital expenditure programs through 2009 are expected to be funded primarily by cash flows from operations and financings. The Company’s Trunkline LNG terminal infrastructure enhancement project, with a current estimated construction cost of approximately $430 million, plus capitalized interest, is still expected to be placed into operation in the third quarter of 2009. Also see Part I, Item 1. Financial Statements (Unaudited), Note 12 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for a discussion related to the Company’s capital expenditure obligations resulting from damages incurred from hurricanes in the third quarter of 2008.

Potential Sea Robin Impairment. Sea Robin, comprised primarily of offshore facilities, suffered damage related to several platforms and gathering pipelines from Hurricane Ike. See Part I, Item 1. Financial Statements (Unaudited), Note 2 – New Accounting Principles and Other Matters – Other Matters for information related to the Company’s analysis of the Sea Robin assets for impairment as of June 30, 2009. The Company currently estimates $130 million of the approximately $180 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin. This estimate is subject to further revision as the damage assessment is ongoing as not all of Sea Robin’s facilities are back in service. The Company anticipates reimbursement from its property insurance carrier for its damages in excess of its $10 million deductible, except for certain expenditures not reimbursable under the insurance policy terms. See Part I, Item 1. Financial Statements (Unaudited), Note 12 – Commitments and Contingencies – Other Commitments and Contingencies – 2008 Hurricane Damage for additional related information. To the extent the Company’s capital expenditures are not recovered through insurance proceeds, its net investment in Sea Robin’s property and equipment would increase without necessarily generating additional revenues unless the incremental costs are recovered through future rate proceedings. If the amount of Sea Robin’s insurance reimbursements are significantly reduced from the currently estimated 63 percent payout limit amount or it experiences other adverse developments incrementally impacting the Company’s related net investment or 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.

Financing activities. Financing activities used cash flows of $140.5 million in the six months ended June 30, 2009 and provided cash flows of $223.8 million in the same period in 2008. The $364.3 million increase in net financing cash outflows was primarily due to a decrease in net debt issuances of $192.8 million, a $128.5 million increase in payments under the Company’s revolving credit facilities and $100 million of cash received by the Company from the issuances of common stock in the 2008 period, partially offset by a $48.6 million cash outflow in the 2008 period for the purchase of 191,884 shares of the Company’s Preferred Stock.

Retirement of Debt Obligations

The Company repaid its $60.6 million 6.50% Senior Notes which matured in July 2009 using a portion of the proceeds from the $150 million 8.125% Senior Notes. The Company also prepaid the $150 million Short-Term Facility in July 2009 using borrowings under its Credit Facilities, in anticipation of closing on the 2009 Term Loan, which occurred on August 5, 2009. The Company has $100 million 6.089% Senior Notes maturing in February 2010 and $40.5 million 8.25% Senior Notes maturing in April 2010, which the Company may choose to retire upon maturity by utilizing some combination of cash flows from operations, draw downs under existing Credit Facilities and altering the timing of controllable cash flows, among other things. The Company believes that it will have sufficient liquidity under its Credit Facilities to redeem the total $140.5 million of debt coming due in 2010.

Credit Facilities

The Company has $420 million available under its committed credit facilities. As of August 5, 2009, there was a balance of $110 million outstanding under the Company’s credit facilities, with an effective interest rate of 0.89 percent.

Credit Ratings. On August 4, 2009, Fitch Ratings lowered the ratings on Panhandle’s debt from BBB to BBB-. Southern Union’s ratings were affirmed at BBB-. Currently, both Southern Union’s and Panhandle’s debt are rated Baa3 by Moody's Investor Services, Inc. and BBB- by Standard & Poor's. 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," both borrowing costs and the costs of maintaining certain contractual relationships could increase. Lower credit ratings could also adversely affect relationships with state regulators, who may be unwilling to allow the Company to pass along increased debt service costs to natural gas customers.

For additional related information, see Part 1, 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.

Recently Issued Accounting Standards

See Part I, Item 1. Financial Statements (Unaudited), Note 2 – New Accounting Principles, 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.

Matters Impacting the Company’s Unconsolidated Investment in Citrus

Florida Power & Light Company (FPL), a Florida Gas customer, filed a proposal with the Florida Public Service Commission (FPSC) in April 2009 for construction of a 300-mile Florida EnergySecure intrastate pipeline from Bradford County to Palm Beach County, Florida. Such project could adversely impact Florida Gas’ ultimate contract terms for the remaining uncommitted Phase VIII Expansion transportation capacity and Florida Gas’ future growth opportunities in Florida.

Florida Gas intervened in the FPSC proceeding to oppose approval of the Florida EnergySecure intrastate pipeline, and Florida Gas representatives offered testimony in hearings before the FPSC on July 27-28, 2009. A ruling by the FPSC is expected in September 2009.

In addition, as part of its proposal, FPL has entered into a non-binding letter of intent with an affiliate of El Paso to negotiate, on an exclusive basis, definitive agreements for the provision by such El Paso affiliate of upstream transportation for the Florida EnergySecure pipeline. Florida Gas had also participated in FPL’s RFP process for the project. The Company, Citrus and Florida Gas, on the one hand, and El Paso, which owns a 50% interest in Citrus, on the other hand, have a pending disagreement concerning the El Paso affiliate’s bid on such project.

Potential Green House Gas (GHG) Emissions Legislation

Various legislative and regulatory bodies have proposed or implemented measures addressing GHG emissions at both the federal and state levels including bills pending in Congress that would regulate GHG emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of GHG. GHG regulation could increase the price of natural gas, restrict the use of natural gas, adversely affect the ability to operate our natural gas facilities and/or reduce natural gas demand. Although additional GHG regulation is likely, it is too early to predict how such regulation will affect our business, operations or financial results.

Rate Matters

Trunkline LNG Cost and Revenue Study. On July 1, 2009, Trunkline LNG filed a Cost and Revenue Study in compliance with FERC orders with respect to the prior Trunkline LNG facility expansions completed in 2006. BG LNG Services, LLC (BGLS) filed a motion to intervene and protest on July 14, 2009. Due to the negotiated rate provisions of the contracts with BGLS, extending through the end of 2015, the Company believes that the final disposition of these Cost and Revenue Study proceedings will not have an impact on Trunkline LNG’s revenues through the end of 2015.

Florida Gas Rate Filing. Pursuant to its last rate case settlement effective March 2005, Florida Gas is required to file a new rate case with FERC on or before October 1, 2009. Florida Gas currently expects to file the rate case on October 1, 2009, with new rates expected to go into effect on April 1, 2010, subject to refund.

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, 2008, 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.

The Company had approximately $34.7 million of interest rate swap fair value liabilities at June 30, 2009 that were measured using significant unobservable inputs. Although the Company does not have sufficient corroborative market evidence to support classifying these level 3 liabilities within level 2, the Company does not utilize significant unobservable inputs that are based on its own internal assumptions within these level 3 liabilities. Rather, the Company utilizes composite yield curves developed by the bank counterparty in determining the period-end fair value of its interest rate swaps. For additional related information, See Part I, Item 1. Financial Statements (Unaudited), Note 11 – Fair Value Measurement, in 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, 2009, the interest rate on 90 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps. At June 30, 2009, $17 million is included in Derivative instruments – liabilities, and $17.7 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.

At June 30, 2009, a 100 basis point move in the annual interest rate on all outstanding floating-rate long-term and short-term debt would increase the Company’s interest payments by approximately $425,000 for each month during which such increase continued. If interest rates changed significantly, the Company would take actions to manage its exposure to the change. No change has been assumed, as a specific action and the possible effects are uncertain.

The Company has entered into treasury rate locks from time to time to manage its exposure against changes in future interest payments attributable to changes in the 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 six-month period ended June 30, 2009 is not material to the Company.

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 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 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.

To manage its commodity price risk related to natural gas and NGL, the Company may use a combination of natural gas puts, price swaps and basis swaps, NGL processing spread puts and swaps’ and other exchange-traded futures and options. These derivative instruments allow the Company to preserve value and protect margins because changes in the value of the derivative instruments are highly effective in offsetting changes in physical market commodity prices and reducing basis risk. Basis risk exists primarily due to price differentials between cash market delivery locations and futures contract delivery locations.

The Company realizes NGL and/or natural gas volumes from the contractual arrangements associated with the gas processing services it provides. Expected NGL 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;

·	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;

·	Reduction in available NGL take-away capacity;

·	Reduction in NGL available from wellhead supply;

·	Lower than expected recovery of NGL from the inlet gas stream; and

·	Lower than expected receipt of natural gas volumes to be processed.

The following table summarizes SUGS' principal commodity derivative instruments as of June 30, 2009 (all instruments are settled monthly), which were developed based upon operating conditions and expected equity (Company-owned) natural gas and NGL sales volumes.

		Average						Fair Value
		Fixed Price		Volumes (MMBtu/d)				of Assets
Instrument Type	Index	(per MMBtu)		2009 (3)		2010 (3)		(Liabilities) (4)
								(In thousands)
Natural Gas - Cash Flow Hedges (1)
Receive-fixed swap	Gas Daily - Waha		$6.69		22,100		-	$	11,820
Receive-fixed swap	Gas Daily - Waha		$5.42		-		13,812		(450	)
Receive-fixed swap	Gas Daily - El Paso Permian		$6.69		17,900		-		9,574
Receive-fixed swap	Gas Daily - El Paso Permian		$5.42		-		11,188		(365	)
		Total			40,000		25,000	$	20,579

Processing Spread - Economic Hedges (2)
Receive-fixed swap	Gas Daily - Waha (natural gas)
	OPIS - Mt. Belvieu (NGL)		$7.18		19,337		-	$	5,163
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)
	OPIS - Mt. Belvieu (NGL)		$7.18		15,663		-		4,182
		Total			35,000		-	$	9,345

__________________

(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 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: 33 percent ethane, 32 percent propane, 5 percent isobutane, 14 percent normal butane and 16 percent natural gasoline. The change in fair value is reported in current-period earnings.

(3)	All volumes are applicable to the period July 1, 2009 to December 31, 2009 or January 1, 2010 to December 31, 2010 as applicable.

(4)	See Part I, Item 1. Financial Statements (Unaudited), Note 10 – Derivative Instruments and Hedging Activities – Commodity Contracts – Gathering and Processing Segment for additional information on derivatives entered into in 2009.

At June 30, 2009, 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 $0.10 per MMBtu of natural gas would impact annual gross margin by approximately $1.7 million and $250,000, 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.

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 operating compression to move the customers’ 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, 2009, there were no hedges in place in respect to natural gas price risk associated with the Company’s interstate pipeline operations.

Distribution Segment. The Company enters into pay-fixed natural gas price swaps to mitigate price volatility of purchased natural gas passed through to customers in the Distribution segment. The cost of the derivative products and the settlement of the respective obligations are recorded through the 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 unaudited interim Condensed Consolidated Balance Sheet. As of June 30, 2009 and December 31, 2008, the fair values of the contracts, which expire at various times through June 2011, are included in the unaudited interim Condensed Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of gas of $71 million and $92.7 million, respectively.

ITEM 4. Controls and Procedures.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Southern Union 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, 2009.

Changes in Internal Controls.

Management’s assessment of internal control over financial reporting as of December 31, 2008 was included in Southern Union’s Annual Report on Form 10-K filed on February 26, 2009.

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Cautionary Statement Regarding Forward-Looking Information

The disclosure and analysis in this Form 10-Q contains some forward-looking statements that set forth anticipated results based on management’s plans and assumptions. From time to time, Southern Union also provides forward-looking statements in other materials it releases to the public as well as oral forward-looking statements. Such statements give the Company’s current expectations or forecasts of future events; they do not relate strictly to historical or current facts. Southern Union has tried, wherever possible, to identify such statements by using words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “will” and similar expressions in connection with any discussion of future operating or financial performance. In particular, these include statements relating to future actions, future performance or results of current and anticipated services, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

Southern Union cannot guarantee that any forward-looking statement will be realized, although management believes that the Company has been prudent in its plans and assumptions. Achievement of future results is subject to risks, uncertainties and potentially inaccurate assumptions. If known or unknown risks or uncertainties should materialize, or if underlying assumptions should prove inaccurate, actual results could differ materially from past results and those anticipated, estimated or projected. Readers should bear this in mind as they consider forward-looking statements. Southern Union undertakes no obligation publicly to update forward-looking statements, whether as a result of new information, future events or otherwise. Readers are advised, however, to consult any further disclosures the Company makes on related subjects in its Form 10-K, 10-Q and 8-K reports to the SEC. Also note that Southern Union provides the following cautionary discussion of risks, uncertainties and possibly inaccurate assumptions relevant to its businesses. These are factors that, individually or in the aggregate, management believes could cause the Company’s actual results to differ materially from expected and historical results. Southern Union notes these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. Readers should understand that it is not possible to predict or identify all such factors. Consequently, readers should not consider the following to be a complete discussion of all potential risks or uncertainties.

Factors that could cause actual results to differ materially from those expressed in the Company’s forward-looking statements include, but are not limited to, the following:

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

·	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 than normal weather in the Company’s service territories, and the operational impact of natural disasters;

·	changes in laws or regulations, third-party relations and approvals, decisions of courts, regulators and governmental bodies affecting or involving Southern Union, 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 is introduced to Southern Union’s business and the resulting effect on revenues;

·	the outcome of pending and future litigation;

·	the Company’s ability to comply with or to challenge successfully existing or new environmental regulations;

·	unanticipated environmental liabilities;

·	the Company’s exposure to highly competitive commodity businesses through its Gathering and Processing segment;

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

·	the Company’s 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, gas pipeline system constraints and relations with labor unions representing bargaining-unit employees;

·	exposure to customer concentration 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 debt securities of Southern Union or any of its subsidiaries;

·	changes in interest rates and other general capital markets conditions, and in the Company’s ability to continue to access the capital markets;

·	acts of nature, sabotage, terrorism or other acts causing damage greater than the Company’s insurance coverage limits;

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

·	other risks and unforeseen events.

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 18 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2008.

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 18 – Commitments and Contingencies, information included in the Company’s Form 10-K for the year ended December 31, 2008.

ITEM 1A. Risk Factors.

There have been no material changes to the risk factors previously disclosed in the Company’s Form 10-K for the year ended December 31, 2008 filed with the SEC on February 26, 2009.

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, 2009 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 of		Average Price
Period	Shares Purchased (1)		Paid per Share
April 1, 2009 through April 30, 2009		6,081	$	15.59
May 1, 2009 through May 31, 2009		49		16.35
June 1, 2009 through June 30, 2009		5,372		16.67
Total		11,502	$	16.10

__________________

(1)	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. Submission of Matters to a Vote of Security Holders.

On May 28, 2009, Southern Union held its Annual Meeting of Stockholders. Each of the proposals submitted to a shareholder vote received the votes necessary for approval. The following matters were voted on by Southern Union’s shareholders:

(I) A proposal to elect eleven directors to serve until the next annual meeting of stockholders or until their successors

are duly elected and qualified.

Nominee	Total Votes For		Total Votes Withheld
Michal Barzuza		114,012,697		4,145,438
Stephen C. Beasley		103,695,033		14,463,102
David L. Brodsky		108,207,174		9,950,961
Frank W. Denius		113,273,089		4,885,046
Michael J. Egan		103,680,665		14,477,470
Kurt A. Gitter, MD		113,389,651		4,768,484
Herbert H. Jacobi		114,041,331		4,116,804
George L. Lindemann		111,918,574		6,239,561
Thomas N. McCarter, III		108,446,846		9,711,289
George Rountree, III		107,294,564		10,863,571
Allan D. Scherer		108,107,103		10,051,032

(II) A proposal to ratify the appointment of PricewaterhouseCoopers LLP as the Company’s independent registered

public accounting firm for the year ending December 31, 2009.

For			116,958,327
Against			1,118,013
Abstain			81,795
Non-votes			0

(III) A proposal to approve the adoption of the Company’s third amended and restated 2003 stock and incentive plan.

For			86,887,411
Against			19,741,721
Abstain			239,152
Non-votes			11,289,851

ITEM 5. Other Information.

All information required to be reported on Form 8-K for the quarter ended June 30, 2009 was appropriately reported.

ITEM 6. Exhibits.

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

2(a)

Purchase and Sale Agreement by and among SRCG, Ltd. and SRG Genpar, L.P., as Sellers and Southern Union Panhandle LLC and Southern Union Gathering Company LLC, as Buyers, dated as of December 15, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on December 16, 2005 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.)

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.)

2(g)	Redemption Agreement by and between CCE Holdings, LLC and Energy Transfer Partners, L.P., dated as of September 18, 2006. (Filed as Exhibit 10.1 to Southern Union’s

Current Report on Form 8-K filed on September 18, 2006 and incorporated herein by reference.)

2(h) Letter Agreement by and between Southern Union Company and Energy Transfer Partners, L.P., dated as of September 14, 2006. (Filed as Exhibit 10.2 to Southern Union’s

Current Report on Form 8-K filed on September 18, 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 through January 3, 2007. (Filed as Exhibit 3.1 to Southern Union’s Current Report on Form 8-K filed on January 3, 2007 and incorporated herein by reference.)

3(c)	Certificate of Designations, Preferences and Rights re: Southern Union Company’s 7.55% Noncumulative Preferred Stock, Series A. (Filed as Exhibit 4.1 to Southern Union’s Form 8-A/A dated October 17, 2003 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)

Indenture between The Bank of New York Mellon Trust Company, N.A., as successor to Chase Manhattan Bank, N.A., as trustee, and Southern Union Company dated January 31, 1994. (Filed as Exhibit 4.1 to Southern Union's Current Report on Form 8-K dated February 15, 1994 and incorporated herein 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 The Bank of New York Mellon Trust Company, N.A., as successor to JP Morgan Chase Bank (formerly the Chase Manhattan Bank, National Association). (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 The Bank of New York Mellon Trust Company, N.A., as successor to JP Morgan Chase Bank, N.A. (f/n/a JP Morgan Chase Bank). (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 Company and The Bank of New York Mellon Trust Company, N.A., as successor to JP Morgan Chase Bank (as successor to The Chase Manhattan Bank, 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.)

4(h)

Second Supplemental Indenture, dated October 23, 2006, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., successor to JP Morgan Chase Bank, N.A., formerly known as JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank (National Association). (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)

Settlement Agreement, dated as of March 5, 2009, among the Company, Sandell Asset Management Corp., Castlerigg Master Investment Ltd., Castlerigg International Limited and Castlerigg International Holdings Limited. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 5, 2009 and incorporated herein by reference.)

10(b)

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(c)

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(d)

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(e)

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(f)

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.)

10(g)

Fifth Amended and Restated Revolving Credit Agreement, dated as of June 20, 2008, among the Company, as borrower, and the lenders party thereto. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on June 25, 2008 and incorporated herein by reference.)

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)

Separation Agreement and General Release Agreement between Thomas F. Karam and Southern Union Company dated November 8, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on November 8, 2005 and incorporated herein by reference.)

10(n)

Separation Agreement and General Release Agreement between John E. Brennan and Southern Union Company dated July 1, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(o)

Separation Agreement and General Release Agreement between David J. Kvapil and Southern Union Company dated July 1, 2005. (Filed as Exhibit 10.4 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)

10(p)

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(q)

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

10(r)

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(s)

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(t)

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(u)

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(v)

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(w)

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(x)

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(y) 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 Company’s Annual Report on Form 10-K for the year ended December

31, 2008 and incorporated herein by reference.)

10(z) 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(aa) 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.

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.

* Management contract or compensation plan or arrangement

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 6, 2009	By /s/ GEORGE E. ALDRICH
	George E. Aldrich Senior Vice President and Controller (authorized officer and principal accounting officer)