suform10q_33109.htm

10-Q 1 suform10q_33109.htm SOUTHERN UNION FORM 10-Q MARCH 31, 2009 suform10q_33109.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

March 31, 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 May 1, 2009 was 124,047,270.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

March 31, 2009

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)
Glossary
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.	31

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	42

ITEM 4. Controls and Procedures.	45

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.	46

ITEM 1A. Risk Factors.	46

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	47

ITEM 3. Defaults Upon Senior Securities.	47

ITEM 4. Submission of Matters to a Vote of Security Holders.	47

ITEM 5. Other Information.	47

ITEM 6. Exhibits.	47

SIGNATURES	52

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 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

Grey Ranch Grey Ranch Plant, LP

IEPA Illinois Environmental Protection Agency

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

MDEP Massachusetts Department of Environmental Protection

MDPU Massachusetts Department of Public Utilities

MGPs Manufactured gas plants

MMBtu Million British thermal units

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three Months Ended
	March 31,
	2009			2008
	(In thousands, except per share amounts)

Operating revenues (Note 11)	$	683,863		$	952,698

Operating expenses:
Cost of gas and other energy		380,062			610,169
Operating, maintenance and general		128,677			108,910
Depreciation and amortization		52,470			48,623
Revenue-related taxes		17,206			18,950
Taxes, other than on income and revenues		13,741			12,491
Total operating expenses		592,156			799,143

Operating income		91,707			153,555

Other income (expenses):
Interest expense		(48,370	)		(50,701	)
Earnings from unconsolidated investments		16,573			16,729
Other, net		5,962			338
Total other income (expenses), net		(25,835	)		(33,634	)

Earnings before income taxes		65,872			119,921

Federal and state income tax expense (Note 9)		19,615			37,013


Net earnings		46,257			82,908

Preferred stock dividends		(2,171	)		(4,341	)

Net earnings available for common stockholders	$	44,086		$	78,567

Net earnings available for common stockholders per share:
Basic	$	0.36		$	0.65
Diluted		0.36			0.64

Dividends declared on common stock per share	$	0.15		$	0.15

Weighted average shares outstanding (Note 5):
Basic		124,045			121,803
Diluted		124,075			122,139

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	March 31,			December 31,
	2009			2008
	(In thousands)
Current assets:
Cash and cash equivalents	$	5,529		$	4,318
Accounts receivable, net of allowances of
$8,099 and $6,003, respectively		278,506			327,358
Accounts receivable – affiliates		12,182			14,743
Inventories (Note 4)		207,316			337,858
Deferred gas purchases		73,364			64,330
Gas imbalances - receivable		140,676			174,100
Derivative instruments (Notes 12 and 15)		63,279			91,423
Prepayments and other assets		9,411			18,226
Total current assets		790,263			1,032,356

Property, plant and equipment:
Plant in service		6,007,602			5,980,297
Construction work in progress		517,199			451,359
		6,524,801			6,431,656
Less accumulated depreciation and amortization		(1,024,367	)		(974,651	)
Net property, plant and equipment		5,500,434			5,457,005

Deferred charges:
Regulatory assets		76,959			69,554
Deferred charges		59,873			59,958
Total deferred charges		136,832			129,512

Unconsolidated investments (Note 6)		1,276,038			1,259,270

Goodwill		89,227			89,227

Other		24,764			30,537


Total assets	$	7,817,558		$	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

	March 31,			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		1,895,492			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: 608
and 663 shares, respectively		(10,955	)		(11,908	)
Deferred compensation plans		10,955			11,908
Accumulated other comprehensive loss		(47,538	)		(51,423	)
Retained earnings		338,761			313,282
Total stockholders' equity		2,398,878			2,367,952

Long-term debt obligations (Note 7)		3,157,069			3,257,434

Total capitalization		5,555,947			5,625,386

Current liabilities:
Long-term debt due within one year (Note 7)		160,623			60,623
Notes payable		303,542			401,459
Accounts payable and accrued liabilities		192,096			246,884
Federal, state and local taxes payable		53,859			54,027
Accrued interest		55,508			41,141
Gas imbalances - payable		240,669			341,987
Derivative instruments (Notes 12 and 15)		102,488			77,554
Other		125,707			128,190
Total current liabilities		1,234,492			1,351,865

Derivative instruments (Notes 12 and 15)		40,323			59,768

Deferred credits		242,262			238,338

Accumulated deferred income taxes		744,534			722,550

Commitments and contingencies (Note 10)

Total stockholders' equity and liabilities	$	7,817,558		$	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)

	Three Months Ended March 31,
	2009			2008
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	46,257		$	82,908
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		52,470			48,623
Deferred income taxes		14,634			26,165
Unrealized (gain) loss on commodity derivatives		15,218			(3,125	)
Earnings from unconsolidated investments, adjusted
for cash distributions		(16,573	)		8,088
Provision for bad debts		1,611			719
FAS 123R expense		1,772			1,353
Changes in operating assets and liabilities		121,341			74,823
Net cash flows provided by operating activities		236,730			239,554
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment		(119,974	)		(228,365	)
Return of investment in Citrus (Note 6)		-			15,933
Plant retirements and other		1,409			(3,166	)
Net cash flows used in investing activities		(118,565	)		(215,598	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in book overdraft		1,923			(19,159	)
Issuance of common stock		-			100,000
Dividends paid on common stock		(18,600	)		(17,999	)
Dividends paid on preferred stock		(2,171	)		(4,341	)
Net change in revolving credit facilities		(97,917	)		(58,000	)
Proceeds from exercise of stock options		-			2,753
Other		(189	)		(211	)
Net cash flows provided by (used in) financing activities		(116,954	)		3,043
Change in cash and cash equivalents		1,211			26,999
Cash and cash equivalents at beginning of period		4,318			5,690
Cash and cash equivalents at end of period	$	5,529		$	32,689

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		-		-		-			-			-			-			-			46,257			46,257
Net change in other
comprehensive income (Note 3)		-		-		-			-			-			-			3,885			-			3,885
Comprehensive income																								50,142
Preferred stock dividends		-		-		-			-			-			-			-			(2,171	)		(2,171	)
Common stock dividends declared		-		-		-			-			-			-			-			(18,607	)		(18,607	)
Share-based compensation		-		-		1,772			-			-			-			-			-			1,772
Restricted stock issuances		45		-		(255	)		-			-			-			-			-			(210	)
Contributions to Trust		-		-		-			-			(192	)		192			-			-			-
Disbursements from Trust		-		-		-			-			1,145			(1,145	)		-			-			-
Balance March 31, 2009	$	125,167	$	115,000	$	1,895,492		$	(28,004	)	$	(10,955	)	$	10,955		$	(47,538	)	$	338,761		$	2,398,878

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 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 amends and expands the disclosure requirements of Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (Statement No. 133) 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 under Statement No. 133 and its related interpretations 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 15 – Derivative Instruments and Hedging Activities, which reflects the disclosure required by this Statement.

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, FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, “Fair Value Measurements”, when the volume and level of activity for the asset or liability have significantly decreased. This FSP 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, FSP FAS 107-1 and APB 28-1 amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments”, to require 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 amends APB Opinion No. 28, “Interim Financial Reporting”, to require 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 amends FASB Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide 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.

Other Matters.

Asset Impairment. The Company applies the provisions of FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (Statement No.144), to account for impairments on long-lived assets. 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 March 31, 2009 because indicators of potential impairment were evident primarily due to the impacts associated with Hurricane Ike. Based upon the Company’s analysis, no impairment of the carrying value of the Sea Robin assets has occurred at this time.

3. Comprehensive Income (Loss)

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

	Three Months Ended
	March 31,
Comprehensive Income (Loss)	2009			2008
	(In thousands)

Net Earnings	$	46,257		$	82,908
Changes in Other Comprehensive Income (Loss):
Change in fair value of interest rate hedges, net of tax of $(415),
and $(13,283), respectively		(618	)		(20,503	)
Reclassification of unrealized loss on interest rate hedges
into earnings, net of tax of $1,612 and $390, respectively		2,429			609
Change in fair value of commodity hedges, net of tax of $4,588,
and $(4,589), respectively		8,142			(8,142	)
Reclassification of unrealized (gain) loss on commodity hedges
into earnings, net of tax of $(3,967) and $54, respectively		(7,040	)		96
Prior service cost relating to other postretirement benefit
plan amendment, net of tax of $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 and $431, respectively		972			643
Total other comprehensive income (loss)		3,885			(33,900	)
Total comprehensive income	$	50,142		$	49,008

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

4. 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 March 31, 2009	(In thousands)
Current
Natural gas held for operations (1)	$	123,570	$	-	$	-	$	123,570
Materials and Supplies		14,973		9,307		4,601		28,881
NGL (2)		-		717		-		717
Natural gas in underground storage (3)		-		-		54,148		54,148
Total Current		138,543		10,024		58,749		207,316

Non-Current
Natural gas held for operations (1)		11,637		-		-		11,637

	$	150,180	$	10,024	$	58,749	$	218,953


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 March 31, 2009 and December 31, 2008 were 29,409,000 MMBtu and 31,751,000 MMBtu,

respectively.

(2)	NGL at March 31, 2009 and December 31, 2008 was 1,448,000 gallons and 20,453,000 gallons, respectively.

(3)	Natural gas volumes in underground storage at March 31, 2009 and December 31, 2008 were 7,151,000 MMBtu and 12,702,000 MMBtu, respectively.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. 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
	March 31,
	2009		2008
	(In thousands)

Weighted average shares outstanding - Basic		124,045		121,803
Add assumed vesting of restricted stock		27		20
Add assumed exercise of stock options and SARs		3		316
Weighted average shares outstanding - Diluted		124,075		122,139

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.

	March 31,
	2009		2008
	(In thousands, except per share amounts)

Options excluded		1,564		717
Exercise price of options excluded		$14.65 - $28.48		$28.48
SARs excluded		399		416
Exercise price ranges of SARs excluded		$28.07 - $28.48		$28.07 - $28.48
First quarter weighted-average market price		$13.67		$26.41

6. Unconsolidated Investments

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

	March 31,		December 31,
Unconsolidated Investments	2009		2008
	(In thousands)
Equity investments:
Citrus	$	1,254,141	$	1,238,198
Other		21,897		21,072
	$	1,276,038	$	1,259,270

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Equity Investments. Unconsolidated investments at March 31, 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 March 31,
	2009				2008
	Citrus		Other		Citrus		Other
	(In thousands)

Revenues	$	111,442	$	5,390	$	112,324	$	4,362
Operating income		54,594		1,910		57,505		1,461
Net earnings		26,422		1,896		26,431		1,440

Citrus.

Dividends. During the three-month period ended March 31, 2009, Citrus did not pay dividends to the Company. In the three-month period ended March 31, 2008, Citrus paid dividends of $40.8 million to the Company, of which $15.9 million has been reflected by the Company as a return of investment.

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 approximately $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 Pipeline Relocation Costs. The FDOT/FTE has various turnpike widening projects that have or may, over time, impact one or more of Florida Gas’ mainline pipelines located in FDOT/FTE rights-of-way. Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new rights-of-way needed for relocation of the pipelines and Florida Gas to pay for rearrangement or relocation costs. Under certain other conditions, Florida Gas may be entitled to reimbursement for the costs associated with relocation, including construction and rights-of-way costs.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

On October 20, 2005, Florida Gas filed an application with FERC for a State Road 91 Relocation Project. The first phase of the turnpike project included replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE rights-of-way in Broward County, Florida to accommodate the widening of State Road 91 by the FDOT/FTE. The FERC issued an order approving the project on May 3, 2006, and Florida Gas notified the FERC that construction commenced on April 25, 2007. Florida Gas received authorization from the FERC to place the facilities in service on March 20, 2008 and the State Road 91 Relocation facilities were placed in service on the same day. In an order issued October 10, 2008, FERC denied a certificate amendment filed by Florida Gas seeking to hold in abeyance the abandonment authorization of the 18- and 24- inch pipelines and ordered Florida Gas to remove the 18- and 24-inch pipelines from service in accordance with a prior order. Florida Gas is also in discussions with the FDOT/FTE related to additional projects that may affect Florida Gas’ 18- and 24-inch 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 have also been the subject of state court litigation. On January 25, 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 complaint seeks damages for breach of easement and relocation agreements for the 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 an amended answer and counterclaim against Florida Gas on February 5, 2008 in the Broward County action. The counterclaim alleges Florida Gas is subject to estoppel and breach of contract claims regarding removal from service of the existing 18- and 24-inch pipelines related to the State Road 91 Relocation Project and seeks 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. On February 14, 2008 the case was transferred to the Broward County Complex Business Civil Division 07. On April 14, 2008, the FDOT/FTE amended its counterclaim, alleging Florida Gas committed fraud in the inducement by not removing its previously existing pipelines, seeking to place a constructive trust over any revenues associated with the previously existing and newly constructed pipelines, seeking a declaratory order from the Court that Florida Gas has abandoned its previously existing pipelines and seeking a temporary and permanent injunction forcing Florida Gas to remove such pipelines. On July 21, 2008, the Court allowed the FDOT/FTE to further amend its counterclaim to include counts of fraud and trespass but reserved ruling on permitting a demand for punitive damages on those counts. On October 6, 2008, the FDOT/FTE filed a supplemental motion for temporary injunction and a motion for partial summary judgment 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 by the FDOT/FTE as a result of the breach of the easements. Based on a preliminary review of expert reports produced by the FDOT/FTE in April 2009, the FDOT is claiming approximately $18 million in actual damages. The FDOT/FTE is seeking the Court’s permission to supplement these reports with as yet undetermined amounts associated with its claim for a constructive trust over revenues from the subject pipelines for the period between April 2008 and January 2009. Trial is scheduled 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 to accommodate the FDOT/FTE 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 reimbursement will fully compensate Florida Gas for its costs.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 10 – Commitments and Contingencies – Litigation.

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:


	March 31, 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	$	281,156	$	359,765	$	272,165
8.25% Senior Notes due 2029		300,000		237,360		300,000		229,470
7.24% to 9.44% First Mortgage Bonds
due 2020 to 2027		19,500		15,676		19,500		16,248
6.089% Senior Notes due 2010		100,000		96,000		100,000		92,701
7.20% Junior Subordinated Notes due 2066		600,000		276,180		600,000		215,999
Note Payable		3,862		3,862		3,820		3,820
		1,383,127		910,234		1,383,085		830,403

Panhandle
6.05% Senior Notes due 2013		250,000		228,775		250,000		211,646
6.20% Senior Notes due 2017		300,000		244,050		300,000		230,956
6.50% Senior Notes due 2009		60,623		60,320		60,623		59,604
8.25% Senior Notes due 2010		40,500		40,095		40,500		39,668
7.00% Senior Notes due 2029		66,305		49,729		66,305		46,158
7.00% Senior Notes due 2018		400,000		335,880		400,000		318,033
Term Loans due 2012		815,391		746,341		815,391		753,262
Net premiums on long-term debt		1,746		1,746		2,153		2,153
		1,934,565		1,706,936		1,934,972		1,661,480

Total Long-Term Debt Obligations		3,317,692		2,617,170		3,318,057		2,491,883

Credit Facilities		153,542		148,517		251,459		243,205
Short-Term Facility		150,000		148,897		150,000		148,496

Total consolidated debt obligations		3,621,234	$	2,914,584		3,719,516	$	2,883,584
Less current portion of long-term debt		160,623				60,623
Less short-term debt		303,542				401,459
Total long-term debt	$	3,157,069			$	3,257,434

The fair value of the Company’s Term Loans due 2012, the Credit Facilities and the Short-Term Facility as of March 31, 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The fair value of the Company’s other long-term debt as of March 31, 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. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the periods ended March 31, 2009 and 2008 includes the components noted in the table below.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
	2009			2008			2009			2008
	(In thousands)

Service cost	$	738		$	686		$	749		$	564
Interest cost		2,524			2,470			1,348			1,280
Expected return on plan assets		(2,070	)		(2,877	)		(772	)		(807	)
Prior service cost (credit) amortization		138			138			(317	)		(463	)
Recognized actuarial (gain) loss		2,101			1,717			(212	)		(306	)
Sub-total		3,431			2,134			796			268
Regulatory adjustment (1)		(125	)		705			666			666
Net periodic benefit cost	$	3,306		$	2,839		$	1,462		$	934

____________________

(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 FASB Statement No. 87, Employers’ Accounting for Pensions and FASB Statement 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, 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
	March 31,
	2009			2008
	(In thousands)

Income tax expense	$	19,615		$	37,013
Effective tax rate		30	%		31	%

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The decrease in the EITR for the three-month period ended March 31, 2009 was primarily due to the following:

·	Lower state income tax expense, net of the federal income benefit, of $1.6 million and $3.3 million for the

three-month periods ended March 31, 2009 and 2008, respectively; and

·	Increase in the tax benefit (relative to pretax earnings) associated with the dividends received deduction from

the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2009

and 2008, the tax benefit of the dividends received deduction was $5.3 million and $9 million, respectively.

The Company evaluates its tax reserves (unrecognized tax benefits) under the recognition, measurement and derecognition thresholds as prescribed by FIN No. 48. The Company increased the amount of its unrecognized tax benefits for certain state filing positions taken during the current period by $670,000 ($430,000, net of federal tax) during the three-month period ended March 31, 2009. The Company currently has $7.9 million ($5.1 million, net of federal tax) of unrecognized tax benefits as of March 31, 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 U.S. federal, state or local examinations 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. 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 follows the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, Environmental Remediation Liabilities, for recognition, measurement, display and disclosure of environmental remediation liabilities.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 March 31, 2009 and December 31, 2008 to cover probable environmental response actions:

	March 31,		December 31,
	2009		2008
	(In thousands)

Current	$	14,277	$	3,513
Noncurrent		16,354		15,626
Total Environmental Liabilities	$	30,631	$	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. In December 2008, the EPA again extended the SPCC rule compliance dates until November 20, 2009, 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 is implementing a program to remediate such contamination. Remediation and decontamination have been completed at each of the 35 compressor station sites where auxiliary buildings that house the air compressor equipment were impacted by the past use of lubricants containing PCBs. At some locations, PCBs have been identified in paint that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline system, PCBs were discovered on the painted surfaces of equipment in a building that is outside the scope of the compressed air system program and the existing PCB impacted paint program. Assessments indicated PCBs at regulated levels at a number of locations. The assessment amount was increased in 2009 from an estimated total of $3.2 million to $3.7 million.

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, such as the Pierce Waste Oil sites described below, 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Air Quality Control. The KDHE has established certain contingency measures as part of the agency’s ozone maintenance plan for the Kansas City area. These measures will be triggered if there are any new elevated ozone readings in the Kansas City area. One of the NOx emission sources that will be impacted is the PEPL Louisburg compressor station. In addition, the U.S. EPA has revised the ozone standard and the Kansas City area will likely be designated as a non-attainment area under the new and stricter standard. Issues associated with reducing emissions at the Louisburg compressor station are being discussed with the KDHE. In the event KDHE requires emission reductions, it is estimated that approximately $14 million in capital expenditures will be required.

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. In November 2003, the MDEP 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 site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. The Company, working with the MDEP, is in the process of performing assessment work at these properties. In a September 2006 report filed with MDEP, the Company proposed a remedy for the upland portion of the site by means of an engineered barrier. Construction of this remedy was completed in October 2008. Assessment activities continue both on- and off-site to define the nature and extent of the impacts. 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 this 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 this site have been included in Regulatory assets in the Condensed Consolidated Balance Sheet.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 accordance with FASB Statement No. 5, Accounting for Contingencies, 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, the 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 and continues to accrue. In June 2007, the Rhode Island Legislature considered, but failed to adopt, legislation that would have increased the maximum administrative penalty under a Notice of Violation to $50,000/day on a prospective basis. Similar legislation was considered in June 2008 that would have increased the maximum administrative penalty under a Notice of Violation to $25,000/day on a prospective basis. That proposed legislation was not adopted in 2008. Such legislation is again under consideration by the Rhode Island Legislature. 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 from 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. Briefing on the summary judgment motion is complete. The Hearing Officer in the AAD proceeding has not yet issued a ruling on that motion. In consideration of the ongoing settlement discussions described below, the RIDEM administrative proceeding has been stayed. The Company will continue to vigorously defend itself in the AAD proceeding.

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. In February 2008, the Court entered a "Trial Order" superseding several prior orders, and directing that (1) on or about April 24, 2008, the Court will conduct a "Phase I" trial on claims asserted by plaintiffs and by Tiverton against the Company; (2) the Phase I trial will be bifurcated into a liability stage, and, if necessary, a damages stage, with both stages to be tried before the same jury; (3) the discovery cutoff date for the Phase I trial is extended from February 29 to March 21, 2008; (4) if necessary, a “Phase II” trial shall address the Company's third-party claims against the PRPs it has impleaded; and (5) the parties to the Phase II trial shall have 120 days after the Phase I trial to conduct discovery related thereto. The Court subsequently ruled that Tiverton’s claims against the Company will be tried in the Phase II trial. The Company filed a motion seeking extension of the discovery and trial date, which was denied in material part. The Phase I 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 November 2008, the plaintiffs filed a motion to enforce a settlement they claim was reached with the Company in April 2008. Plaintiffs also filed a motion to seal the papers related to the motion to enforce. In December 2008, the Company filed its opposition to the motion to enforce asserting that no settlement was reached. In December 2008, the Company also filed a motion to recuse the Court from all further substantive proceedings in the case, and filed its own motion supporting the sealing of all papers on the motion to enforce. On December 16, 2008, the Court issued a memorandum and order (i) denying the motion to seal the papers related to the motion to enforce, which papers the Court then placed in the public file; and (ii) granting the motion to recuse the Court from all further substantive matters in the case. The case has been assigned to another Judge who held an evidentiary hearing on February 6, 2009 on plaintiffs’ motion to enforce. The Court has not rendered a decision on the motion to enforce. On March 6, 2009, at the Court’s direction, the plaintiffs, the Town of Tiverton and the Company participated in a mediation. Settlement discussions amongst the parties are ongoing. No settlement has been reached. A new trial date has not been set. 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 December 1, 2008, the Company filed motions for acquittal and alternatively for a new trial with respect to the RCRA count on which the Company was found guilty. Briefing on such motions is now complete except for an additional briefing requested by the Court on the issue of the maximum amount of any potential fine. The Company is to submit a brief on the issue by May 12, 2009 and the Government will have two weeks to respond. In the event the Company’s motions for acquittal and/or for a new trial are not granted, sentencing as regards the single RCRA count is presently set for June 25, 2009. 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.

In January 2006, a complaint was filed against the Company in the Superior Court in Providence, Rhode Island regarding the mercury release from the Pawtucket facility, asserting claims for personal injury and property damage as a result of the release. The suit was removed to Rhode Island federal court. A motion to remand the case to state court filed by plaintiffs was denied in April 2007. The Company thereafter moved to dismiss plaintiffs’ amended complaint, which motion was granted in part, dismissing claims for public nuisance, private nuisance and violation of Rhode Island’s Hazardous Waste Management Act, leaving plaintiffs with claims for negligence and strict liability. In October 2007, an attorney representing other Pawtucket residents filed suit against the Company in the Superior Court in Providence asserting claims similar to those pending in the above-described federal court suit for personal injury and property damage. An additional complaint alleging personal injury arising out of the mercury release was filed on behalf of three plaintiffs with the District Court for the Sixth District, Providence County, Rhode Island, in January 2008. Settlement discussions with regard to the civil suits are ongoing and have not yet been finalized. The Company will vigorously defend all such suits. 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.

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. 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

Other Commitments and Contingencies

Retirement of Debt Obligations. The Company plans to repay its $60.6 million 6.50% Senior Notes maturing in July 2009 and expects to arrange to refinance the $150 million Short-Term Facility due in August 2009 and the $100 million 6.089% Senior Notes maturing in February 2010. The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance these obligations under acceptable terms prior to their maturity. However, there can be no assurance that the Company would be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Should the Company not be successful in its refinancing efforts, the Company may choose to retire such debt 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.

2008 Hurricane Damage. In September 2008, Hurricanes Gustav and Ike came ashore on the Louisiana and Texas coasts. Damage from the hurricanes have 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 are continuing to experience reduced volumes. 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 estimate relating to the hurricane was increased to approximately $150 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 $42 million of the capital replacement and retirement expenditures were incurred as of March 31, 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 maximum payout amount from 84 percent to no more than 70 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11. 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.

Revenue included in the Corporate and other category is primarily attributable to PEI Power Corporation, which generates and sells electricity. PEI Power Corporation does not meet the quantitative threshold for segment reporting.

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-month periods ended March 31, 2009 and 2008.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Three Months Ended
	March 31,
Segment Data	2009		2008
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	192,295	$	187,051
Gathering and Processing		168,305		415,662
Distribution		322,024		348,635
Total segment operating revenues		682,624		951,348
Corporate and other		1,239		1,350
Total consolidated revenues from external
customers	$	683,863	$	952,698

Depreciation and amortization:
Transportation and Storage	$	27,863	$	25,061
Gathering and Processing		16,413		15,470
Distribution		7,671		7,572
Total segment depreciation and amortization		51,947		48,103
Corporate and other		523		520
Total depreciation and amortization expense	$	52,470	$	48,623

Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	15,784	$	16,242
Gathering and Processing		528		318
Corporate and other		261		169
	$	16,573	$	16,729

Segment performance:
Transportation and Storage EBIT (1)	$	93,222		$	114,100
Gathering and Processing EBIT		(11,433	)		28,556
Distribution EBIT (1)		31,638			28,482
Total segment EBIT		113,427			171,138
Corporate and other (1)		815			(516	)
Interest expense		48,370			50,701
Federal and state income tax expense		19,615			37,013
Net earnings		46,257			82,908
Preferred stock dividends		2,171			4,341
Net earnings available for common stockholders	$	44,086		$	78,567

__________________

(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 allocation to the Distribution segment for the three months ended March 31, 2009 was $2.3 million. 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

For comparability between reporting periods purposes, 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 March 31, 2008
			Recast Adjustments
Segment	EBIT as Reported		Increase (Decrease)			Recast EBIT
			(In thousands)

Transportation and Storage	$	109,381	$	4,719		$	114,100
Distribution		30,301		(1,819	)		28,482
Corporate and Other		2,384		(2,900	)		(516	)

	March 31,		December 31,
Segment Data	2009		2008
	(In thousands)
Total assets:
Transportation and Storage	$	4,920,793	$	4,969,336
Gathering and Processing		1,691,278		1,764,497
Distribution		1,109,693		1,177,124
Total segment assets		7,721,764		7,910,957
Corporate and other		95,794		86,950
Total consolidated assets	$	7,817,558	$	7,997,907


	Three Months Ended
	March 31,
	2009		2008
		(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	77,712	$	182,166
Gathering and Processing		11,218		17,469
Distribution		6,562		5,704
Total segment expenditures for
long-lived assets		95,492		205,339
Corporate and other		6,916		1,220
Total consolidated expenditures for
long-lived assets (1)	$	102,408	$	206,559

_______________________

(1) Includes net period changes in capital accruals totaling $(9.9) million and $(21.8) million for the three-month periods ended March 31, 2009 and 2008, respectively.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

12. 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 March 31, 2009.


			Fair Value Measurements Using Fair Value Hierarchy
At March 31, 2009	Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Signficant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Assets:
Cash equivalents (money
market investments)	$	602	$	602	$	-	$	-
Commodity derivatives (1), (2)		63,279		-		63,279		-
Long-term investments		643		643		-		-
Total	$	64,524	$	1,245	$	63,279	$	-

Liabilities:
Commodity derivatives (2)	$	101,668	$	-	$	101,668	$	-
Interest-rate derivatives (2)		41,143		-		-		41,143
Total	$	142,811	$	-	$	101,668	$	41,143

__________________

(1)	The Company’s commodity derivative asset balance is primarily associated with two separate counterparties, each individually comprising $42.2 million and $19.8 million of the related fair value as of March 31, 2009.

(2)	See related information in Note 15 – 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 March 31, 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		-			-			943
Purchases and settlements, net		-			(206	)		(3,430	)
Transfers out of level 3		(1,254	)		239			-
Ending balance	$	-		$	-		$	41,143

___________________

(1)	The amount included in operating revenues for the three months ended March 31, 2009 that is attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities held at March 31, 2009 were gains of $725,000 and 221,000, respectively.

13. 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. Cost projections continue to indicate the construction costs will be approximately $430 million, plus capitalized interest. Approximately $397.3 million and $351.3 million of costs, including capitalized interest, are included in the line item Construction work-in-progress at March 31, 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

14. Stockholders’ Equity

Dividends. On April 10, 2009, the Company paid its regular quarterly cash dividend of $0.15 per share on the Company’s common stock. Dividend payments totaling $18.6 million were paid to holders of record as of March 27, 2009.

15. 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. In accordance with Statement No. 133, 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 March 31, 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 March 31, 2009, approximately $10.8 million of net after-tax losses in Accumulated other comprehensive loss related to these interest rate swaps will 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 March 31, 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 March 31, 2009, approximately $1.2 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 March 31, 2009, the Company had outstanding receive-fixed natural gas price swaps with a total notional amount of 5,500,000 MMBtus for the remainder of 2009. 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 March 31, 2009, approximately $20.8 million of net after-tax gains in Accumulated other comprehensive loss related to these natural gas price swaps will be amortized into Operating revenues during the remainder of 2009. Any ineffective portion of the cash flow hedge is reported in current-period earnings.

NGL Processing Spread Swaps. As of March 31, 2009, the Company had outstanding receive-fixed NGL processing spread swaps with a total notional amount of 8,250,000 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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company enters into other derivative instruments, including natural gas price swaps and basis swaps, 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 March 31, 2009, the Company had outstanding forward contracts for the sale of 432,000 MMBtus of natural gas at fixed prices through December 2009. These forward contracts are derivatives under Statement No. 133, with changes in their fair value recorded in Operating revenues. As of March 31, 2009, the Company had outstanding receive-floating natural gas price swaps and NYMEX to WAHA basis swaps with total notional amounts of 355,000 MMBtus and 370,000 MMBtus, respectively, that are associated with the forward contracts. These natural gas price swaps and basis swaps are accounted for as economic hedges, with changes in their fair value recorded in Operating revenues. As of March 31, 2009, the Company had outstanding WAHA to Houston Ship basis swaps that are associated with the delivery of 10,000 MMBtu per day of natural gas through November 2009 at delivery points different from supply points. These natural gas basis 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 March 31, 2009, the Company had outstanding pay-fixed natural gas price swaps with total notional amounts of 16,530,000 MMBtus, 15,360,000 MMBtus and 240,000 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 in accordance with FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.”

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Summary Financial Statement Information

The following table summarizes the location and fair value amounts of the Company’s derivative instruments reported in the Condensed Consolidated Balance Sheet at March 31, 2009.


	Asset Derivatives			Liability Derivatives
Balance Sheet Location		Fair Value (1)		Balance Sheet Location	Fair Value (1)
		(In thousands)			(In thousands)
Cash Flow Hedges
Interest rate contracts:
Interest rate swaps		$	-	Current liabilities	$	16,065
			-	Noncurrent liabilities		25,078
Commodity contracts - Gathering and Processing:
Natural gas price swaps	Current assets		32,476			-
		$	32,476		$	41,143
Economic Hedges
Commodity contracts - Gathering and Processing:
NGL processing spread swaps	Current assets	$	29,550		$	-
Other derivative instruments	Current liabilities		473	Current liabilities		1,381

Commodity contracts - Distribution:
Natural gas price swaps			-	Current liabilities		85,515
			-	Noncurrent liabilities		15,245
		$	30,023		$	102,141
Other
Commodity contracts - Gathering and Processing:
Other derivative instruments	Current assets	$	1,253		$	-

Total		$	63,752		$	143,284

_____________

(1)	See Note 12 – Fair Value Measurement for information related to the framework used by the Company to measure the fair value of its derivative instruments as of March 31, 2009.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following tables summarize the location and amount of derivative instrument gains and losses reported in the Company’s condensed consolidated financial statements for the period presented.

	Three Months Ended
	March 31, 2009
Cash Flow Hedges (1)	(In thousands)
Interest rate contracts:
Change in fair value - increase in Accumulated other comprehensive loss,
excluding tax expense effect of $415	$	1,033
Reclassification of unrealized loss from Accumulated other comprehensive loss -
increase of Interest expense, excluding tax expense effect of $1,612		4,041
Loss on ineffectiveness of hedges		-

Commodity contracts - Gathering and Processing:
Change in fair value - decrease in Accumulated other comprehensive loss,
excluding tax expense effect of $4,588		12,730
Reclassification of unrealized gain from Accumulated other comprehensive loss -
increase of Operating revenues, excluding tax expense effect of $3,967		11,007
Loss on ineffectiveness of hedges		-

Economic Hedges
Commodity contracts - Gathering and Processing:
Change in fair value - decrease in Operating revenues		21,368

Commodity contracts - Distribution:
Change in fair value - increase in Deferred charges - Regulatory assets		8,076

Other
Commodity contracts - Gathering and Processing:
Change in fair value - increase in Operating revenues		289

__________________

(1)	See Note 3 – 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 March 31, 2009 is $33 million.

16. Other Income (Expense), Net

Other, net income in the Condensed Consolidated Statement of Operations for the three-month period ended March 31, 2009 totaling $6 million consists primarily of $5.4 million related to an insurance settlement. In March 2009, the Company entered into a settlement agreement with an insurance company that released it 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. 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.

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

	Three Months Ended
	March 31,
	2009			2008
	(In thousands)
EBIT:
Transportation and storage segment (1)	$	93,222		$	114,100
Gathering and processing segment		(11,433	)		28,556
Distribution segment (1)		31,638			28,482
Corporate and other (1)		815			(516	)
Total EBIT		114,242			170,622
Interest		48,370			50,701
Earnings before income taxes		65,872			119,921
Federal and state income tax expense		19,615			37,013
Net earnings		46,257			82,908
Preferred stock dividends		2,171			4,341

Net earnings available for common stockholders	$	44,086		$	78,567

________________

(1)

	Three Months Ended March 31, 2008
			Recast Adjustments
Segment	EBIT as Reported		Increase (Decrease)			Recast EBIT
			(In thousands)

Transportation and Storage	$	109,381	$	4,719		$	114,100
Distribution		30,301		(1,819	)		28,482
Corporate and Other		2,384		(2,900	)		(516	)

Three-month period ended March 31, 2009 versus the three-month period ended March 31, 2008. The Company’s $34.5 million decrease in Net earnings available for common stockholders in the three-month period ended March 31, 2009 versus the same period in 2008 was primarily due to:

Lower EBIT contributions of $40 million from the Gathering and Processing segment primarily due to lower operating revenues of $233.4 million, largely attributable to lower market driven realized average natural gas and NGL prices and the impact of $13.9 million of higher net hedging losses, partially offset by lower market driven natural gas and NGL purchase costs of $206.8 million in the 2009 period versus the 2008 period;

Lower EBIT contributions of $20.9 million from the Transportation and Storage segment primarily due to higher operating expenses of $22.2 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 $2 million, a $1.3 million charge for a lower of cost or market system gas inventory adjustment in 2009 and a $1.2 million increase in LNG power costs resulting from actual costs recovered in rates through the power reimbursement mechanism, and higher depreciation and amortization expense of $2.8 million primarily due to increases in plant, property, and equipment, partially offset by higher operating revenues of $5.2 million attributable to higher transportation and storage revenues of $3.7 million and higher LNG terminalling revenues of $2.2 million;

These reductions to earnings were partially offset by:

·	Impact of $3.5 million and $1.9 million of income in 2009 recorded in the Distribution and Corporate and other segments, respectively, related to a settlement agreement with an insurance company that released it from certain potential future environmental claim obligations;

Lower interest expense of $2.3 million primarily attributable to lower interest expense of $3.6 million due to lower LIBOR interest rates associated with the Company’s variable rate debt, partially offset by higher net interest expense of $1.5 million due to higher net debt balances outstanding on fixed-rate debt obligations;

·	Lower preferred stock dividends of $2.2 million due to the Company’s repurchase in 2008 of 459,999 shares of its 7.55% Noncumulative Preferred Stock, Series A shares; and

Lower federal and state income tax expense of $17.4 million primarily due to lower pre-tax earnings of $54 million and the impact of the reduced EITR attributable to a lower state income tax expense (net of the federal income tax benefit) of $1.7 million and an increase in the tax benefit (relative to 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
	March 31,
Transportation and Storage Segment	2009		2008
	(In thousands)

Operating revenues	$	192,295	$	187,051

Operating expenses		78,194		55,973
Depreciation and amortization		27,863		25,061
Taxes other than on income and revenues		8,925		8,649
Total operating income		77,313		97,368
Earnings from unconsolidated investments		15,784		16,242
Other income, net		125		490
EBIT	$	93,222	$	114,100

Operating information:
Panhandle natural gas volumes transported (TBtu)		427		401
Florida Gas natural gas volumes transported (TBtu) (1)		187		173

________________

(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 March 31, 2009 versus the three-month period ended March 31, 2008. The $20.9 million EBIT reduction in the three-month period ended March 31, 2009 versus the same period in 2008 was primarily due to a lower EBIT contribution from Panhandle totaling $20.4 million and lower equity earnings of $500,000, principally from the Company’s unconsolidated investment in Citrus.

Panhandle’s $20.4 million EBIT reduction was primarily due to:

·	Higher operating revenues of $5.2 million primarily attributable to:

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

Higher transportation reservation revenues of $2.2 million primarily due to an increase of approximately $4.4 million attributable to the completion of the primary portion of the Trunkline Field Zone Expansion project during the period December 2007 to February 2008 and a smaller second phase completed in November 2008, 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;

o	Lower transportation commodity revenues of $3.4 million primarily due to reduced volumes flowing after Hurricane Ike; and

A $2.2 million increase in LNG terminalling revenue primarily due to $1.2 million associated with a change in the reimbursement mechanism in the fourth quarter of 2008 that allows the Company to recover actual monthly LNG power costs from the customer and approximately $1 million of higher reservation revenues attributable to a one-time annual rate increase associated with certain capacity effective January 1, 2009.

The increased revenues were offset by:

·	Higher operating expenses of $22.2 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 $2 million increase in contract storage costs resulting from an increase in leased storage capacity;

o	A charge of $1.3 million in 2009 to record a lower of cost or market adjustment for system gas owned by the Company; and

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

Increased depreciation and amortization expense of $2.8 million due to a $222 million increase in property, plant and equipment placed in service after March 31, 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 10 – 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 $500,000 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 $2.9 million primarily due to interest on a $500 million construction and term loan agreement issued in February 2008, partially offset by lower average outstanding revolver debt balances;

·	Higher depreciation expense of $600,000 primarily due to increased plant, property, and equipment placed in service;

·	Higher operating expenses of $600,000 primarily due to higher overall costs experienced in 2009 applicable to employee labor and benefits, legal services costs, and other operating costs;

·	Lower operating revenues of $400,000 primarily attributable to the extra day in the 2008 leap year, partially offset by increased capacity from prior expansions; and

·	Higher other income of $4.1 million primarily due to higher AFUDC resulting from Florida Gas’ Phase VIII Expansion project.

See Part I. Item I. Financial Statements (Unaudited), Note 6 – 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.

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

	Three Months Ended
	March 31,
Gathering and Processing Segment	2009			2008
	(In thousands)

Operating revenues, excluding impact of
commodity derivative instruments	$	178,377		$	411,788
Realized and unrealized commodity derivatives		(10,072	)		3,874
Operating revenues		168,305			415,662
Cost of gas and other energy		(143,129	)		(348,200	)
Gross margin (1)		25,176			67,462
Operating expenses		19,662			22,949
Depreciation and amortization		16,413			15,470
Taxes other than on income and revenues		1,340			801
Total operating income		(12,239	)		28,242
Earnings from unconsolidated investments		528			318
Other expense, net		278			(4	)
EBIT	$	(11,433	)	$	28,556


Operating information:
Volumes
Avg natural gas processed (MMBtu/d)		420,904			408,082
Avg NGL produced (gallons/d)		1,370,712			1,336,032
Avg natural gas wellhead (MMBtu/d)		578,558			623,149
Natural gas sales (MMBtu)		21,557,171			24,159,245
NGL sales (gallons) (2)		166,091,347			154,660,401

Average Pricing
Realized natural gas ($/MMBtu) (3)	$	3.50		$	7.79
Realized NGL ($/gallon) (3)		0.60			1.42
Natural Gas Daily WAHA ($/MMBtu)		3.42			8.00
Natural Gas Daily El Paso ($/MMBtu)		3.31			7.92
Estimated plant processing spread ($/gallon)		0.29			0.69

________________

(1)

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.

(2)

Volumes processed by SUGS include volumes sold under various buy-sell arrangements. For the three-month periods ended March 31, 2009 and 2008, the Company’s operating revenues and related volumes attributable to its buy-sell arrangements for natural gas totaled $11.7 million and $28.9 million, and 3.3 million MMBtus and 3.6 million MMBtus, respectively. The Company’s operating revenues and related volumes for the three-month periods ended March 31, 2009 and 2008 attributable to its buy-sell arrangements for NGL totaled $11.9 million and $47.5 million, and 20.8 million gallons and 34.5 million gallons, respectively.

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

Three-month period ended March 31, 2009 versus the three-month period ended March 31, 2008. The $40 million EBIT reduction in the three-month period ended March 31, 2009 versus the same period in 2008 was primarily due to the following items:

·	Lower gross margin of $42.3 million primarily as the result of:

Lower operating revenues of $233.4 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 $3.50 per MMBtu and $0.60 per gallon in the 2009 period versus $7.79 per MMBtu and $1.42 per gallon in the 2008 period, respectively;

o	Impact of lower market driven natural gas and NGL purchase costs of $206.8 million in the 2009 period versus the 2008 period; and

o	Impact of $13.9 million of net hedging losses in the 2009 period versus the 2008 period (which includes the impact of $15.2 million of unrealized losses recorded in 2009);

·	Higher depreciation and amortization expense of $900,000 primarily attributable to a $49 million increase in property, plant and equipment placed in service after March 31, 2008; and

·	Lower operating expenses of $3.3 million primarily due to:

o	A $1.1 million decrease in maintenance and contract services costs largely attributable to a 2009 cost reduction initiative primarily related to the Company’s variable and discretionary costs;

o	A $500,000 decrease in chemical and lubricants costs, which generally track with the price of oil;

o	A $400,000 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	Lower corporate services costs of $300,000.

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 87 percent of its total natural gas sales customers and approximately 67 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
	March 31,
Distribution Segment	2009		2008
	(In thousands)

Net operating revenues (1)	$	68,188	$	68,111

Operating expenses		29,229		28,880
Depreciation and amortization		7,671		7,572
Taxes other than on income
and revenues		3,092		2,989
Total operating income		28,196		28,670
Other income (expenses), net		3,442		(188	)
EBIT	$	31,638	$	28,482

Operating Information:
Gas sales volumes (MMcf)		29,640		33,135
Gas transported volumes (MMcf)		8,349		9,634

Weather – Degree Days: (2)
Missouri Gas Energy service territories		2,494		2,921
New England Gas Company service territories		2,970		2,654

________________

(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 March 31, 2009 versus the three-month period ended March 31, 2008. The $3.2 million EBIT improvement in the three-month period ended March 31, 2009 versus the same period in 2008 was primarily due to:

·	Higher Other Income, net, of $3.6 million primarily due to a settlement of $3.5 million with an insurance company that released it from certain potential future environmental claim obligations;

Net operating revenues were flat primarily due to a higher contribution of $2.3 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 and colder weather, offset by $2.2 million of lower net operating revenues at Missouri Gas Energy primarily due to the impact of warmer weather for its non-residential customers; and

·	Higher operating expenses of $300,000 primarily attributable to:

o	Higher injuries and damage claims of $2.2 million primarily due to the impact of an insurance reimbursement of $900,000 received in 2008 and higher ongoing litigation costs;

o	Higher provisions for uncollectible customer accounts of approximately $900,000 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 in 2008 of a $2.4 million reserve related to completed site investigation evaluations.

Corporate and Other

Three-month period ended March 31, 2009 versus the three-month period ended March 31, 2008. The EBIT improvement of $1.3 million was primarily due to:

·	A settlement of $1.9 million in March 2009 with an insurance company that released it from certain potential future environmental claim obligations; and

Lower contributions of $800,000 from PEI Power Corporation primarily due to 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 revenues of $100,000 primarily due to lower electricity prices in 2009.

Interest Expense

Three-month period ended March 31, 2009 versus the three-month period ended March 31, 2008. Interest expense was $2.3 million lower in the three-month period ended March 31, 2009 versus the same period in 2008 primarily due to:

·	Lower interest expense of $3.6 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 $800,000 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 interest expense of $1.5 million primarily due to a higher outstanding debt balance from the $400 million 7.00% Senior Notes issued in June 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
	March 31,
	2009			2008
	(In thousands)

Income tax expense	$	19,615		$	37,013
Effective tax rate		30	%		31	%

Three-month period ended March 31, 2009 versus the three-month period ended March 31, 2008. The $17.4 million reduction of federal and state income tax expense was primarily due to lower pre-tax earnings of $54 million and the impact of the lower EITR for the three-month period ended March 31, 2009 which was primarily due to:

·	Lower state income tax expense, net of the federal income benefit, of $1.6 million and $3.3 million for the three-month periods ended March 31, 2009 and 2008, respectively; and

Increase in the tax benefit (relative to pretax earnings) associated with the dividends received deduction from the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2009 and 2008, the tax benefit of the dividends received deduction was $5.3 million and $9 million, respectively.

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 March 31, 2009 is $444.2 million. This includes $60.6 million and $100 million of long-term debt maturing in July 2009 and February 2010, respectively, and $150 million of short-term debt due in August 2009. 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 there is no way to 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 current expectation that the impact on the Company would be significant.

Sources (Uses) of Cash

	Three months ended March 31,
	2009			2008
	(In thousands)
Cash flows provided by (used in):
Operating activities	$	236,730		$	239,554
Investing activities		(118,565	)		(215,598	)
Financing activities		(116,954	)		3,043
Increase (decrease) in cash and cash equivalents	$	1,211		$	26,999

Operating activities. Cash provided by operating activities decreased by $2.8 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 $115.4 million compared with $164.7 million for the 2008 period, a decrease of $49.3 million primarily resulting from lower net earnings in 2009. Changes in operating assets and liabilities provided cash of $121.3 million in the 2009 period and $74.8 million in the 2008 period, resulting in an increase in cash from changes in operating assets and liabilities of $46.5 million in 2009 compared to 2008. The $46.5 million increase is primarily due to the impact of decreased accounts receivables of $40.5 million in the Distribution segment primarily due to warmer weather for Missouri Gas Energy’s nonresidential customers and increased cash of $9.1 million from the sale of previously inventoried NGL in the Gathering and Processing segment related to the build up of NGL inventory because of an outage of the third party NGL fractionator during the fourth quarter of 2008.

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 North American natural gas markets.

Cash flows used in investing activities in the three months ended March 31, 2009 and 2008 were $118.6 million and $215.6 million, respectively. The $97 million reduction in invested cash outflows is primarily due to a $104.5 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.

	Three Months Ended
	March 31,
Property, Plant and Equipment Additions	2009			2008
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	41,092		$	48,506
Trunkline Field Zone Expansion		828			59,004
East End Enhancement		(18	)		29,138
Compression Modernization		1,657			19,714
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance and hurricane
expenditures		34,153			25,804
Total		77,712			182,166

Gathering and Processing Segment		11,218			17,469

Distribution Segment
Missouri Safety Program		2,367			2,395
Other, primarily system replacement
and expansion		4,195			3,309
Total		6,562			5,704

Corporate and other		6,916			1,220

Total (1)	$	102,408		$	206,559

_______________

(1)	Includes net period changes in capital accruals totaling $(9.9) million and $(21.8) million for the three-month periods ended March 31, 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 10 – 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 March 31, 2009. The Company currently estimates $100 million of the approximately $150 million total estimated capital replacement and retirement expenditures to replace property and equipment damaged by Hurricane Ike are related to Sea Robin. This estimate is subject to further revision as the damage assessment is ongoing. 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 10 – 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 maximum 70 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 pursuant to FASB Statement No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.”

Financing activities. Financing activities used cash flows of $117 million in the three months ended March 31, 2009 and provided cash flows of $3 million in the same period in 2008. The $120 million decrease in financing cash inflows was primarily due to a $39.9 million increase in payments under the Company’s revolving credit facilities in the 2009 period and $100 million of cash received by the Company from the issuances of common stock in the 2008 period.

Retirement of Debt Obligations

The Company plans to repay its $60.6 million 6.50% Senior Notes maturing in July 2009 and expects to arrange to refinance the $150 million Short-Term Facility due in August 2009 and the $100 million 6.089% Senior Notes maturing in February 2010. The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance these obligations under acceptable terms prior to their maturity. However, there can be no assurance that the Company would be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Should the Company not be successful in its refinancing efforts, the Company may choose to retire such debt 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.

Credit and Short-Term Facilities

The Company has $420 million available under its committed credit facilities. As of May 1, 2009, there was a balance of $149.1 million outstanding under the Company’s credit facilities, with an effective interest rate of 1.23 percent. Additionally, as of May 1, 2009, there was a balance of $150 million outstanding under the Short-Term Facility, with an effective interest rate of 1.71 percent.

OTHER MATTERS

Contingencies

See Part I, Item 1. Financial Statements (Unaudited), Note 10 – 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 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.

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.

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 $41.1 million of interest rate swap fair value liabilities at March 31, 2009 that were measured using significant unobservable inputs (i.e. Statement No. 157 level 3 liabilities). 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 12 – 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 March 31, 2009, the interest rate on 89 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At March 31, 2009, $16 million is included in Derivative instruments – current liabilities, and $25.1 million is included in Derivative instruments – noncurrent liabilities 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 March 31, 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 three-month period ended March 31, 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 March 31, 2009 (all instruments are settled monthly), which were developed based upon operating conditions and expected equity (Company-owned) natural gas and NGL sales volumes.

Instrument Type	Index	Average Fixed Price (per MMBtu)		Volumes (MMBtu/d) (3)		Fair Value of Assets
						(In thousands)
Natural Gas - Cash Flow Hedges (1)
Receive-fixed swap	Gas Daily - Waha	$	9.49		11,050	$	17,943
Receive-fixed swap	Gas Daily - El Paso Permian	$	9.49		8,950		14,533
		Total			20,000	$	32,476

Processing Spread - Economic Hedges (2)
Receive-fixed swap	Gas Daily - Waha (natural gas)	$	7.40		16,575	$	16,326
	OPIS - Mt. Belvieu (NGL)
Receive-fixed swap	Gas Daily - El Paso Permian (natural gas)	$	7.40		13,425		13,224
	OPIS - Mt. Belvieu (NGL)
		Total			30,000	$	29,550

__________________

(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 April 1, 2009 to December 31, 2009.

At March 31, 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 March 31, 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 March 31, 2009 and December 31, 2008, the fair values of the contracts, which expire at various times through February 2011, are included in the unaudited interim Condensed Consolidated Balance Sheet as liabilities, with matching adjustments to deferred cost of gas of $100.8 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 March 31, 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 March 31, 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 10 – 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 10 – 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 March 31, 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
January 1, 2009 through January 31, 2009		9,470	$	13.53
February 1, 2009 through February 28, 2009		70		12.97
March 1, 2009 through March 31, 2009		24,850		13.88
Total		34,390	$	13.78

__________________

(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.

N/A

ITEM 5. Other Information.

All information required to be reported on Form 8-K for the quarter ended March 31, 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 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 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 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 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 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.

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.

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: May 11, 2009	By /s/ GEORGE E. ALDRICH
	George E. Aldrich Senior Vice President and Controller (authorized officer and principal accounting officer)