Edgar Filing: SOUTHERN UNION CO

suform10q_033108.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, 2008

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

Securities Registered Pursuant to Section 12(g) of the Act: None

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 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 ___ 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 2, 2008 was 124,003,265.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

March 31, 2008

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)

ITEM 1. Financial Statements (Unaudited):

Condensed consolidated statement of operations.	2

Condensed consolidated balance sheet.	3-4

Condensed consolidated statement of cash flows.	5

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

Notes to condensed consolidated financial statements.	7

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	26

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	35

ITEM 4. Controls and Procedures.	38

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.	40

ITEM 1A. Risk Factors.	40

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	41

ITEM 3. Defaults Upon Senior Securities.	41

ITEM 4. Submission of Matters to a Vote of Security Holders.	41

ITEM 5. Other Information.	41

ITEM 6. Exhibits.	42

SIGNATURES	46

Table of Contents

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,
	2008			2007
	(In thousands, except per share amounts)

Operating revenues (Note 11)	$	952,698		$	780,232

Operating expenses:
Cost of gas and other energy		610,169			483,085
Operating, maintenance and general		108,910			95,195
Depreciation and amortization		48,623			43,464
Revenue-related taxes		18,950			17,019
Taxes, other than on income and revenues		12,491			11,875
Total operating expenses		799,143			650,638
Operating income		153,555			129,594
Other income (expenses):
Interest expense		(50,701	)		(52,185	)
Earnings from unconsolidated investments		16,729			30,896
Other, net		338			287
Total other income (expenses), net		(33,634	)		(21,002	)
Earnings before income taxes		119,921			108,592
Federal and state income tax expense (Note 9)		37,013			29,871
Net earnings		82,908			78,721
Preferred stock dividends		(4,341	)		(4,341	)
Net earnings available for common stockholders	$	78,567		$	74,380

Net earnings available for common stockholders per share:
Basic	$	0.65		$	0.62
Diluted		0.64			0.62

Dividends declared on common stock per share	$	0.15		$	0.10

Weighted average shares outstanding (Note 5):
Basic		121,803			119,790
Diluted		122,139			120,277

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	March 31,			December 31,
	2008			2007
	(In thousands)
Current assets:
Cash and cash equivalents	$	32,689		$	5,690
Accounts receivable, net of allowances of
$5,584 and $4,144, respectively		392,290			358,521
Accounts receivable – affiliates		6,252			29,943
Inventories (Note 4)		172,898			263,618
Gas imbalances - receivable		228,652			105,371
Prepayments and other assets		60,887			45,181
Total current assets		893,668			808,324
Property, plant and equipment:
Plant in service		5,703,165			5,509,992
Construction work in progress		378,331			377,918
		6,081,496			5,887,910
Less accumulated depreciation and amortization		(827,884	)		(785,623	)
Net property, plant and equipment		5,253,612			5,102,287
Deferred charges:
Regulatory assets		69,543			64,193
Deferred charges		63,036			60,468
Total deferred charges		132,579			124,661

Unconsolidated investments (Note 6)		1,237,704			1,240,420

Goodwill		89,227			89,227

Other		27,734			32,994

Total assets	$	7,634,524		$	7,397,913

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	March 31,			December 31,
	2008			2007
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
125,064 shares issued at March 31, 2008	$	125,064		$	121,102
Preferred stock, no par value; 6,000 shares authorized;
920 shares issued at March 31, 2008		230,000			230,000
Premium on capital stock		1,884,358			1,784,223
Less treasury stock: 1,066 and 1,063
shares, respectively, at cost		(27,921	)		(27,839	)
Less common stock held in trust: 709
and 783 shares, respectively		(14,028	)		(15,085	)
Deferred compensation plans		14,091			15,148
Accumulated other comprehensive loss		(45,494	)		(11,594	)
Retained earnings		169,826			109,851
Total stockholders' equity		2,335,896			2,205,806

Long-term debt obligations (Note 7)		2,949,758			2,960,326

Total capitalization		5,285,654			5,166,132

Current liabilities:
Long-term debt and capital lease obligation
due within one year (Note 7)		444,552			434,680
Notes payable		65,000			123,000
Accounts payable and accrued liabilities		315,966			335,253
Federal, state and local taxes payable		48,566			35,461
Accrued interest		50,233			45,911
Customer deposits		15,395			17,589
Deferred gas purchases		48,568			-
Gas imbalances - payable		369,855			272,850
Other		76,443			58,969
Total current liabilities		1,434,578			1,323,713

Deferred credits		217,163			215,063

Accumulated deferred income taxes		697,129			693,005

Commitments and contingencies (Note 10)

Total stockholders' equity and liabilities	$	7,634,524		$	7,397,913

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

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2008			2007
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings	$	82,908		$	78,721
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		48,623			43,464
Deferred income taxes		26,165			24,294
Loss (gain) on derivatives		(3,125	)		843
Earnings from unconsolidated investments, adjusted
for cash distributions		8,088			16,704
Other		2,889			2,119
Changes in operating assets and liabilities		74,006			5,634
Net cash flows provided by operating activities		239,554			171,779
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment		(228,365	)		(70,034	)
Dispositions of operations, net		-			(49,304	)
Return of investment in Citrus (Note 6)		15,933			-
Other		(3,166	)		1,238
Net cash flows used in investing activities		(215,598	)		(118,100	)
Cash flows provided by (used in) financing activities:
Decrease in bank overdraft		(19,159	)		(31,398	)
Issuance costs of debt		(120	)		(525	)
Issuance of common stock		100,000			-
Issuance of long-term debt		-			455,000
Dividends paid on common stock		(17,999	)		(11,961	)
Dividends paid on preferred stock		(4,341	)		(4,341	)
Repayment of debt obligation		-			(462,289	)
Net change in revolving credit facilities		(58,000	)		(5,000	)
Proceeds from exercise of stock options		2,744			1,558
Other		(82	)		255
Net cash flows provided by (used in) financing activities		3,043			(58,701	)
Change in cash and cash equivalents		26,999			(5,022	)
Cash and cash equivalents at beginning of period		5,690			5,751
Cash and cash equivalents at end of period	$	32,689		$	729

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

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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, 2007	$	121,102	$	230,000	$	1,784,223		$	(27,839	)	$	(15,085	)	$	15,148		$	(11,594	)	$	109,851		$	2,205,806
Comprehensive loss:
Net earnings		-		-		-			-			-			-			-			82,908			82,908
Net change in other
comprehensive loss (Note 3)		-		-		-			-			-			-			(33,900	)		-			(33,900	)
Comprehensive income																								49,008
Preferred stock dividends		-		-		-			-			-			-			-			(4,341	)		(4,341	)
Cash dividends declared		-		-		-			-			-			-			-			(18,592	)		(18,592	)
Issuance of common stock		3,693		-		96,307			-			-			-			-			-			100,000
Share-based compensation		-		-		1,353			-			-			-			-			-			1,353
Restricted stock issuances		52		-		(52	)		(82	)		-			-			-			-			(82	)
Exercise of stock options		217		-		2,527			-			-			-			-			-			2,744
Contributions to Trust		-		-		-			-			(585	)		585			-			-			-
Disbursements from Trust		-		-		-			-			1,642			(1,642	)		-			-			-
Balance March 31, 2008	$	125,064	$	230,000	$	1,884,358		$	(27,921	)	$	(14,028	)	$	14,091		$	(45,494	)	$	169,826		$	2,335,896

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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of Southern Union Company (Southern Union) and its subsidiaries (collectively, the Company) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for quarterly reports on Form 10-Q. These statements do not include all of the information and annual note disclosures required by accounting principles generally accepted in the United States of America (GAAP), and should be read in conjunction with the Company’s financial statements and notes thereto for the year ended December 31, 2007, 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. For the three-month period ended March 31, 2007 presented herein, the Company has revised $49.3 million of working capital adjustment payments made in March of 2007 related to the 2006 sales of certain distribution assets. The payments were previously reported within the Condensed Consolidated Statement of Cash Flows for the three-month period ended March 31, 2007, as cash flows used in operating activities rather than cash flows used in investing activities.

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 liquified natural gas (LNG) terminalling and regasification services. The Gathering and Processing segment is primarily engaged in the gathering, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts.

2. New Accounting Principles

Accounting Principles Recently Adopted.

FASB Statement No. 157, “Fair Value Measurements” (Statement No. 157): Issued by the Financial Accounting Standards Board (FASB) in September 2006, this Statement defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Where applicable, this Statement simplifies and codifies related guidance within GAAP. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB released a FASB Staff Position (FSP FAS 157-2, “Effective Date of FASB Statement No. 157”), which delays the effective date of this Statement for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008. The Company’s major categories of non-financial assets and non-financial liabilities that are recognized or disclosed at fair value for which, in accordance with FSP FAS 157-2, the Company has not applied the provisions of Statement No. 157 as of January 1, 2008 are i) fair value calculations associated with annual or periodic impairment tests and ii) asset retirement obligations measured at fair value upon initial recognition or upon certain remeasurement events under FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” The partial adoption on January 1, 2008 of this Statement for financial assets and liabilities did not have a material impact on the Company’s consolidated financial statements. See Note 12 – Fair Value Measurement for more information.

FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”: Issued by the FASB in February 2007, this Statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. The Statement does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Statement is effective for fiscal years beginning after November 15,

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2007. At January 1, 2008, the Company did not elect the fair value option under the Statement and, therefore, there was no impact on the Company’s consolidated financial statements.

Staff Accounting Bulletin No. 110 (SAB 110): Issued by the SEC in December 2007, SAB 110 expresses the views of the SEC staff regarding the use of a “simplified” method, as discussed in SAB No. 107, in developing an estimate of expected term of “plain vanilla” share options in accordance with Statement No. 123R, “Accounting for Stock-Based Compensation.” The SEC staff indicated in SAB No. 107 that it would accept a company’s election to use the simplified method, regardless of whether the company has sufficient information to make more refined estimates of expected term, for options granted prior to December 31, 2007. In SAB 110, the SEC staff states that it will continue to accept, under certain circumstances, the use of the simplified method beyond December 31, 2007. Pursuant to the guidance provided in SAB 110, the Company has elected to continue utilizing the simplified method in developing the estimate of the expected term for its share options.

FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FIN 39-1): Issued by the FASB in April 2007, FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions by allowing net derivative positions to be offset in the financial statements against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral or the obligation to return cash collateral under those arrangements. In accordance with FASB Interpretation No. 39, the Company has historically offset the fair value amounts for derivative instruments executed with the same counterparty where a right of setoff existed, which included derivative instruments subject to master netting arrangements at December 31, 2007. In accordance with FIN 39-1, the Company elects to offset the fair value amounts for derivative instruments, including cash collateral, executed with the same counterparty under a master netting arrangement.

Accounting Principles Not Yet Adopted.

FASB Statement No. 141 (revised), “Business Combinations”. Issued by the FASB in December 2007, this Statement changes the accounting for business combinations including the measurement of acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for preacquisition gain and loss contingencies, the recognition of capitalized in-process research and development costs, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition-related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited.

FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”. Issued by the FASB in December 2007, this Statement changes the accounting for noncontrolling (minority) interests in consolidated financial statements, including the requirements to classify noncontrolling interests as a component of consolidated stockholders’ equity, and the elimination of minority interest accounting in results of operations with earnings attributable to noncontrolling interests reported as part of consolidated earnings. Additionally, the Statement revises the accounting for both increases and decreases in a parent’s controlling ownership interest. The Statement is effective for fiscal years beginning after December 15, 2008, with early adoption prohibited. The Company is currently evaluating the impact of this statement on its consolidated financial statements.

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 requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Statement is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. The Company is currently evaluating the impact of this statement on its consolidated financial statements.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3. Comprehensive Income (Loss)

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

	Three Months Ended
	March 31,
Comprehensive Income (Loss)	2008			2007
	(In thousands)

Net Earnings	$	82,908		$	78,721
Comprehensive Income (Loss) Adjustments:
Change in fair value of interest rate hedges, net of tax of $(13,283)
and $0, respectively		(20,503	)		-
Reclassification of unrealized gain (loss) on interest rate hedges
into earnings, net of tax of $390 and $(3), respectively		609			(1,045	)
Change in fair value of commodity hedges, net of tax of $(4,589)
and $(2,868), respectively		(8,142	)		(4,727	)
Reclassification of unrealized gain (loss) on commodity hedges
into earnings, net of tax of $54 and $(1,287), respectively		96			(2,122	)
Reduction of prior service credit relating to pension and other
postretirement benefits, net of tax of $(3,231) and $0, respectively		(6,603	)		-
Reclassification of net actuarial gain and prior service credit
relating to pension and other postretirement benefits into
earnings, net of tax of $431 and $(77), respectively		643			574
Total other comprehensive loss		(33,900	)		(7,320	)
Total comprehensive income	$	49,008		$	71,401

See Note 8 – Employee Benefits for a discussion related to an amendment of Panhandle's postretirement benefit plans 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 gas held for operations and materials and supplies, both of which are carried 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. Gas held for operations at March 31, 2008 was $148.7 million, or 15,743,000 million British thermal units (MMBtu), of which $10 million was classified as non-current. Gas held for operations at December 31, 2007 was $187 million, or 26,001,000 MMBtu, of which $19 million was classified as non-current. Materials and supplies in the Transportation and Storage segment include spare parts which are critical to the pipeline system operations, and were $13.3 million and $12.8 million at March 31, 2008 and December 31, 2007, respectively.

In the Gathering and Processing segment, inventories consist of materials and supplies and are stated at the lower of weighted average cost or market. Materials and supplies in the Gathering and Processing segment, primarily comprised of compressor components and parts, were $7.5 million and $6.2 million at March 31, 2008 and December 31, 2007, respectively.

In the Distribution segment, inventories consist of natural gas in underground storage and materials and supplies, both of which are carried at weighted average cost. Natural gas in underground storage at March 31, 2008 and December 31, 2007 was $9.6 million and $72.8 million, respectively, and consisted of 1,473,000 MMBtu and 11,823,474 MMBtu, respectively. Materials and supplies inventories in the Distribution segment were $3.8 million and $3.8 million at March 31, 2008 and December 31, 2007, respectively.

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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 stock appreciation rights. 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,
	2008		2007
	(In thousands)

Weighted average shares outstanding - Basic		121,803		119,790
Add assumed vesting of restricted stock		20		26
Add assumed exercise of stock options
and stock appreciation rights		316		461
Weighted average shares outstanding - Dilutive		122,139		120,277

There were 717,000 anti-dilutive stock options and 416,000 anti-dilutive stock appreciation rights outstanding for the three months ended March 31, 2008. There were no anti-dilutive options outstanding for the same period in 2007.

6. Unconsolidated Investments

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

	March 31,		December 31,
Unconsolidated Investments	2008		2007
	(In thousands)
Equity investments:
Citrus	$	1,215,732	$	1,219,009
Other		21,972		21,411
	$	1,237,704	$	1,240,420

Equity Investments. Unconsolidated investments at March 31, 2008 and December 31, 2007 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus Corp. (Citrus), Grey Ranch Plant, LP (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 Condensed Consolidated Statement of Operations.

Dividends. During 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. In the three-month period ended March 31, 2007, Citrus paid dividends of $47.6 million to the Company.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	Three Months Ended				Three Months Ended
	March 31, 2008				March 31, 2007
	Citrus		Other		Citrus		Other
			(In thousands)
Income Statement Data:
Revenues	$	112,324	$	4,362	$	109,038	$	2,215
Operating income (loss)		57,505		1,461		56,875		794
Net earnings		26,431		1,440		40,141		1,692

Phase VIII Expansion. Florida Gas Transmission Company, LLC (Florida Gas), a wholly-owned subsidiary of Citrus, plans to seek approval of the Federal Energy Regulatory Commission (FERC) to construct an expansion to increase its natural gas capacity into Florida by approximately 800 million cubic feet per day (MMcf/d) (Phase VIII Expansion). The proposed Phase VIII Expansion includes construction of approximately 580 miles of additional large diameter pipeline and the installation of approximately 217,000 horsepower of additional compression. Pending FERC approval, which is expected in the latter half of 2009, Florida Gas anticipates an in-service date of 2011, at an approximate cost of $2.1 billion. To date, Florida Gas has entered into precedent agreements with shippers for transportation services for 25-year terms accounting for approximately 75 percent of the available expansion capacity.

On February 5, 2008, Citrus entered into a $500 million unsecured construction and term loan agreement with a wholly-owned subsidiary of FPL Group Capital Inc., which is a wholly-owned subsidiary of FPL Group, Inc. Citrus will invest the proceeds of this loan into Florida Gas in order to finance a portion of the Phase VIII Expansion.

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects that have impacted or may, over time, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way. The first phase of the turnpike project includes replacement of approximately 11.3 miles of the existing 18- and 24-inch pipelines of Florida Gas located in FDOT/FTE right-of-way in Florida. Approximately $101 million of replacement costs have been incurred as of March 31, 2008. No pipeline removal costs have been incurred due to certain delays more fully described below. 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 right-of-way costs, cannot be determined at this time.

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 right-of-way costs. On January 25, 2007, Florida Gas filed a complaint against the FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, seeking relief with respect to three specific sets of FDOT/FTE widening projects in Broward County. The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects on 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 regarding removal from service of the existing pipelines on the project currently under construction 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. As a result of the FDOT/FTE representing that the projects have been delayed, a hearing on the motion by Florida Gas for a temporary injunction enjoining the FDOT/FTE interference with the pipelines of Florida Gas has been taken off the judicial calendar. On April 14, 2008 the FDOT/FTE amended its counter claim, 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

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existing pipelines and seeking a temporary and permanent injunction forcing Florida Gas to remove such lines. 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 such projects, has been stayed pending resolution of the Broward County, Florida action.

On October 24, 2007, Florida Gas filed a complaint in the US District Court of the Northern District of Florida, Tallahassee Division, against Stephanie C. Kopelousos (Kopelousos) in her official capacity as the Secretary of the Florida Department of Transportation, seeking to enjoin Kopelousos from violating federal law in connection with construction of the FDOT/FTE Golden Glades project, a new toll plaza in Miami-Dade County, Florida. Based upon representations by the FDOT/FTE that work would not begin on the Golden Glades project until 2013, the parties entered into a joint stipulation of dismissal without prejudice on February 15, 2008.

Should Florida Gas be denied reimbursement by the FDOT/FTE for any possible relocation expenses, such costs are expected to be covered by operating cash flows and additional borrowings. Florida Gas expects to seek rate recovery at the 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.

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.

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7. Debt Obligations

The following table sets forth the debt obligations of Southern Union and applicable units of Panhandle Eastern Pipe Line Company, LP (PEPL) and its subsidiaries (collectively, Panhandle) under their respective notes, debentures and bonds at the dates indicated:

	March 31,		December 31,
	2008		2007
	(In thousands)
Long-Term Debt Obligations:

Southern Union
7.60% Senior Notes due 2024	$	359,765	$	359,765
8.25% Senior Notes due 2029		300,000		300,000
7.24% to 9.44% First Mortgage Bonds due 2020 to 2027		19,500		19,500
4.375% Senior Notes due 2008		-		100,000
6.15% Senior Notes due 2008		125,000		125,000
6.089% Senior Notes due 2010		100,000		-
7.20% Junior Subordinated Notes due 2066		600,000		600,000
		1,504,265		1,504,265

Panhandle
4.80% Senior Notes due 2008		300,000		300,000
6.05% Senior Notes due 2013		250,000		250,000
6.20% Senior Notes due 2017		300,000		300,000
6.50% Senior Notes due 2009		60,623		60,623
8.25% Senior Notes due 2010		40,500		40,500
7.00% Senior Notes due 2029		66,305		66,305
Term Loans due 2012		867,220		867,220
Net premiums on long-term debt		5,397		6,093
		1,890,045		1,890,741

Total Long-Term Debt Obligations		3,394,310		3,395,006

Credit Facilities		65,000		123,000

Total consolidated debt obligations		3,459,310		3,518,006
Less current portion of long-term debt		444,552		434,680
Less short-term debt		65,000		123,000
Total consolidated long-term debt obligations	$	2,949,758	$	2,960,326

Remarketing Obligation. On February 8, 2008, the Company remarketed the 4.375% Senior Notes, which yielded no cash proceeds for the Company. The interest rate on the Senior Notes was reset to 6.089 percent per annum effective on and after February 19, 2008. The Senior Notes will mature on February 16, 2010. On February 19, 2008, the Company issued 3,693,240 shares of common stock for $100 million in conjunction with the remarketing of its 4.375% Senior Notes.

Retirement of Debt Obligations

The Company plans to refinance its $425 million of debt maturing in August 2008 with new capital market debt or bank financings. Alternatively, 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 expenditures, among other things. The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets, current economic and capital market conditions and market expectations regarding the

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Company's future earnings and cash flows, that it will be able to refinance and/or retire these obligations under acceptable terms prior to their maturity. There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company's inability to do so would cause a material adverse effect on the Company's financial condition and liquidity.

8. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the three-month periods ended March 31, 2008 and 2007 includes the components noted in the table below.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2008			2007			2008			2007
	(In thousands)

Service cost	$	686		$	664		$	564		$	489
Interest cost		2,470			2,287			1,280			1,047
Expected return on plan assets		(2,877	)		(2,382	)		(807	)		(719	)
Prior service cost amortization		138			127			(463	)		(732	)
Recognized actuarial (gain) loss		1,717			1,994			(306	)		(204	)
Sub-total		2,134			2,690			268			(119	)
Regulatory adjustment		705			(2,116	)		666			666
Net periodic benefit cost	$	2,839		$	574		$	934		$	547

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 obligation increase of approximately $9.8 million.

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 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 promulgated by the applicable utility commission in which this difference will be recovered in rates.

9. Taxes on Income

The Company's estimated annual consolidated federal and state effective income tax rate (EITR) for the three-month periods ended March 31, 2008 and 2007 was 31 percent and 28 percent, respectively.

The increase in the EITR for the three-month period was primarily due to the decrease in the tax benefit associated with the dividends received deduction as a result of lower estimated dividends from the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2008 and 2007, the tax benefit of the dividends received deduction was $9 million and $11.5 million, respectively.

The Company is no longer subject to U.S. federal, state or local examinations for the tax year ended June 30, 2004 and prior years. The Company settled the Internal Revenue Service (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. Therefore, the state and local statutes will expire with respect to the tax year ended June 30, 2003 in 2008.

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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.

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 Condensed Consolidated Balance Sheet at March 31, 2008 and December 31, 2007 to cover probable environmental response actions:

	March 31,		December 31,
	2008		2007
	(In thousands)

Current	$	7,008	$	6,772
Noncurrent		15,688		15,209
Total Environmental Liabilities	$	22,696	$	21,981

Spill Prevention, Control and Countermeasure (SPCC) Rules. In May 2007, the U.S. EPA extended the SPCC rule compliance dates until July 1, 2009, permitting owners and operators of facilities to prepare or amend and implement SPCC Plans in accordance with previously enacted modifications to the regulations. In October 2007, the U.S. EPA proposed amendments to the SPCC rules with the stated intention of providing greater clarity, tailoring requirements, and streamlining requirements. 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 gas transmission systems for contamination resulting from the past use of lubricants containing polychlorinated biphenyls (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 has 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

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has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline Gas Company, LLC (Trunkline) system, PCBs were discovered on the painted surfaces of equipment in a building that is outside of the scope of the compressed air system program and the existing PCB impacted paint program. The estimated cost to remediate the painted surfaces at this location is approximately $300,000. An initial assessment program was undertaken at seven locations to determine whether this condition exists at any of the other 78 similar buildings on the PEPL, Trunkline and Pan Gas Storage, LLC (d.b.a. Southwest Gas) systems. As of March 31, 2008, a total of 37 locations have been preliminarily assessed, indicating PCBs at regulated levels in a small number of samples at a total of 13 locations. Until the complete results of the assessment program are available and the analysis is completed, the costs associated with remediation of the painted surfaces cannot be reasonably estimated.

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 potentially responsible parties (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.

PEPL and Trunkline, together with other non-affiliated parties, were identified as potentially liable for conditions at three former waste oil disposal sites in Illinois – the Pierce Oil Springfield site, the Dunavan Waste Oil site and the McCook site (collectively, the Pierce Waste Oil sites). PEPL and Trunkline received notices of potential liability from the U.S. EPA for the Dunavan site by letters dated September 30, 2005. Although no formal notice has been received for the Pierce Oil Springfield site, special notice letters are anticipated and the process of listing the site on the National Priority List has begun. No formal notice has been received for the McCook site. 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.

On June 16, 2005, PEPL experienced a release of liquid hydrocarbons near Pleasant Hill, Illinois. The U.S. EPA took the lead role in overseeing the subsequent cleanup activities, which have been completed. PEPL has resolved claims of affected boat owners and the marina operator. PEPL received a violation notice from the Illinois Environmental Protection Agency (IEPA) alleging that PEPL was in apparent violation of several sections of the Illinois Environmental Protection Act by allowing the release. The violation notice did not propose a penalty. Responses to the violation notice were submitted and the responses were discussed with the agency. In December 2005, the IEPA notified PEPL that the matter might be considered for referral to the Office of the Attorney General, the State’s Attorney or the U.S. EPA for formal enforcement action and the imposition of penalties. There has been no contact from the IEPA on this matter since the Company submitted responses in January 2007 to an IEPA information request. 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.

Air Quality Control. In early April 2007, the IEPA proposed a rule to the Illinois Pollution Control Board (IPCB) for adoption to control NOx emissions from reciprocating engines and turbines, including a provision applying the rule beyond issues addressed by federal provisions, pursuant to a blanket statewide application. After objections were filed with the IPCB, the IEPA filed an amended proposal withdrawing the statewide applicability provisions of the proposed rule and applying the rule requirements to non-attainment areas. The amended proposal was approved on January 10, 2008. No controls on PEPL and Trunkline stations are required under the most recent proposal. However, the IEPA indicated in earlier industry discussions that it was reserving the right to make future proposals for statewide controls. In the event the IEPA proposes a statewide rule again, preliminary estimates indicate the cost of compliance would require minimum capital expenditures of approximately $45 million for emission controls.

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Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems. Southern Union Gas Services (SUGS) is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. Southern Union Gas Services 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.

Air Quality Control. On June 16, 2006, SUGS, as the facility operator and holder of a 50 percent interest in the Grey Ranch facility, submitted information to the TCEQ in connection with a request to permit its Grey Ranch, Texas facility to continue its current level of emissions. The State of Texas requires all previously grandfathered emission sources to obtain permits or shut down by March 1, 2008. By letter dated September 5, 2007, the TCEQ issued a permit extending current emission levels to March 1, 2009. At the conclusion of the extension period, SUGS must implement an emission control strategy that achieves specific maximum allowable emissions rates. It is anticipated that the Company will not bear any of the costs associated with the emission controls. Roc Gas Company, or one of its affiliates, which holds the other 50 percent leasehold interest in the site (and owns the site), will bear all the costs necessary to construct the piping and modify its nearby compression facilities in order to take possession of the emissions, which are primarily CO2, for off-site commercial uses.

Distribution Segment Environmental Matters.

The Company is responsible for environmental remediation at various contaminated sites that are primarily associated with former manufactured gas plants (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.

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North Attleborough MGP Site in Massachusetts. In November 2003, the Massachusetts Department of Environmental Protection (MADEP) issued a Notice of Responsibility to New England Gas Company, acknowledging receipt of prior notifications and investigative reports submitted by New England Gas Company, following the discovery of suspected coal tar material at the site. Subsequent sampling in the adjacent river channel revealed sediment impacts necessitating the investigation of off-site properties. The Company, working with the MADEP, is in the process of performing assessment work at these properties. In a September 2006 report filed with the MADEP, the Company proposed a remedy for the upland portion of the site by means of an engineered barrier, construction of which is anticipated in 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 $8.7 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.

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. On March 17, 2003, the Rhode Island Department of Environmental Management (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 and has continued to perform assessment field work since that time. On September 19, 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. The Rhode Island Legislature is now considering legislation that would increase the maximum administrative penalty under a Notice of Violation to $25,000/day on a prospective basis. On April 19, 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. On July 13, 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 of same based on RIDEM’s unlawful application of its own regulations. Briefing on the summary judgment motion is now complete. The Hearing Officer in the AAD proceeding has not yet issued a ruling on that motion. At this time, the RIDEM administrative proceeding has effectively 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. On November 3, 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

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against the Company under CERCLA. On January 30, 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. On February 13, 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. Trial, which was scheduled to commence on April 28, 2008, has been adjourned to allow the parties to explore settlement opportunities. While the parties have tentatively agreed on a framework, no definitive settlement arrangement has been reached. Based upon its current understanding of the facts, the Company does not believe the outcome of these matters will have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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. On October 16, 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 Resource Conservation and Recovery Act (RCRA) and notification requirements under the federal Emergency Planning and Community Right to Know Act relating to the 2004 incident. The Company entered a not guilty plea on October 29, 2007 and will vigorously defend itself in such action. On January 17, 2008, the Court granted the Company’s motion to extend the deadline for completion of discovery to March 13, 2008, and to extend the deadline for the filing of certain motions to April 8, 2008. In March 2008, the Judge presiding in the case recused himself and the case was reassigned. The Company has filed a motion to dismiss the two RCRA counts of the indictment (Counts I and III), and has filed a number of motions. The Court has not yet ruled on such motions, and has not yet set a trial date, although trial is not expected to commence before the third quarter of 2008. 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.

On January 20, 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 on January 27, 2006. A motion to remand the case to state court filed by plaintiffs was denied on April 16, 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. The Court has set December 1, 2008 as the Closure Date for all discovery. On October 18, 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, on January 22, 2008. 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 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

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(UNAUDITED)

arguments on November 21, 2007. A hearing is set for September 2008. 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.

GP II Energy Litigation. On October 23, 2006, landowners filed suit against the Company in the 109th District Court of Winkler County, Texas. Plaintiffs are seeking money damages, equitable relief and punitive damages alleging continuing pollution to underground aquifers underlying the plaintiffs’ approximately 16,000 acre property. SUGS operated the Halley Plant, a hydrocarbon processing facility, which is located on a limited portion of the plaintiff landowners’ ranch pursuant to a lease. On February 15, 2008, the Company learned that plaintiffs significantly revised their claims to include approximately $40 million in economic damages and approximately $85 million in punitive damages. On March 31, 2008, plaintiffs filed a third amended petition revising their claims to include approximately $96 million in economic damages and approximately $193 million in punitive damages. The trial date is set for June 10, 2008. The Company will continue to vigorously defend the suit. 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.

Hurricane Damage. Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast. These hurricanes caused damage to property and equipment owned by Sea Robin Pipeline Company, LLC (Sea Robin), Trunkline, and Trunkline LNG Company, LLC (Trunkline LNG). As of March 31, 2008, the Company has incurred $35 million of capital expenditures related to the hurricanes, primarily for replacement or abandonment of damaged property and equipment at Sea Robin and construction project delays at the Trunkline LNG terminal.

The Company anticipates reimbursement from its property insurance carriers for a significant portion of damages from the hurricanes in excess of its $5 million deductible. Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 63 percent of the portion of the claimed damages accepted by the insurance carrier, but the amount is subject to the level of total ultimate claims from all companies relative to the carrier’s $1 billion total limit on payout per event that was in effect during 2005. The Company’s property insurance carrier’s $1 billion total limit on payout per event was reduced for subsequent years to $750 million. As of March 31, 2008, the Company has received payments of $7.6 million from its insurance carriers. No receivables due from the insurance carriers have been recorded as of March 31, 2008.

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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.

The Transportation and Storage segment operations are conducted through Panhandle and the Company’s investment in Citrus. Through Panhandle, the Company is primarily engaged in the interstate transportation and storage of natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions. Panhandle also provides LNG terminalling and regasification services. Through its investment in Citrus, the Company has an interest in and operates Florida Gas. Florida Gas is primarily engaged in the interstate transportation of natural gas from South Texas through the Gulf Coast region to Florida.

SUGS, which comprises 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 natural gas liquids (NGLs), and redelivering natural gas and NGLs to a variety of markets. Its operations are conducted throughout Texas and in the southwestern United States.

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

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 earnings before interest and taxes (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; and

·	dividends on 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, 2008 and 2007.

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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	2008		2007
	(In thousands)
Revenues from external customers:
Transportation and Storage	$	187,051	$	169,030
Gathering and Processing		415,662		296,055
Distribution		348,635		314,257
Total segment operating revenues		951,348		779,342
Corporate and other		1,350		890
	$	952,698	$	780,232

Depreciation and amortization:
Transportation and Storage	$	25,061	$	20,709
Gathering and Processing		15,470		14,587
Distribution		7,572		7,618
Total segment depreciation and amortization		48,103		42,914
Corporate and other		520		550
	$	48,623	$	43,464

Segment performance:
Transportation and Storage EBIT	$	109,381	$	115,218
Gathering and Processing EBIT		28,556		8,882
Distribution EBIT		30,301		33,545
Total segment EBIT		168,238		157,645
Corporate and other		2,384		3,132
Interest expense		50,701		52,185
Federal and state income tax expense		37,013		29,871
Net earnings		82,908		78,721
Preferred stock dividends		4,341		4,341
Net earnings available for common stockholders	$	78,567	$	74,380

Expenditures for long-lived assets:
Transportation and Storage	$	182,166	$	46,808
Gathering and Processing		17,469		12,356
Distribution		5,704		7,114
Total segment expenditures for
long-lived assets		205,339		66,278
Corporate and other		1,220		634
Total consolidated expenditures for
long-lived assets (1)	$	206,559	$	66,912

(1) Includes net capital accruals totaling $(21.8) million and $(3.1) million for the three-month periods ended March 31, 2008 and 2007, respectively.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	March 31,		December 31,
Segment Data	2008		2007
	(In thousands)
Total assets:
Transportation and Storage	$	4,785,201	$	4,550,822
Gathering and Processing		1,707,253		1,709,901
Distribution		1,042,283		1,020,460
Total segment assets		7,534,737		7,281,183
Corporate and other		99,787		116,730
Total consolidated assets	$	7,634,524	$	7,397,913

12. Fair Value Measurement

Adoption of Statement No. 157

Effective January 1, 2008, the Company partially adopted Statement No. 157 (see Note 2 – New Accounting Principles) which provides a framework for measuring fair value. As defined in Statement No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to any applicable valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. The Company endeavors to utilize the best available information, including valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Statement No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value as follows:

·	Level 1 – Observable inputs such as quoted prices in active markets for identical assets or liabilities;

Level 2 – Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; or (iii) valuations based on pricing models where significant inputs (e.g., interest rates, yield curves, etc.) are observable for the assets or liabilities, are derived principally from observable market data, or can be corroborated by observable market data;

Level 3 – Unobservable inputs, including valuations based on pricing models where significant inputs are not observable and not corroborated by market data. Unobservable inputs are used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table is a summary of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis in accordance with Statement No. 157.

	Fair Value		Fair Value Measurements at March 31, 2008
	as of		Using Fair Value Hierarchy
	March 31, 2008		Level 1		Level 2		Level 3
	(In thousands)
Assets:
Commodity derivatives	$	30,190	$	-	$	29,168	$	1,022
Long-term investments		941		941		-		-
Total	$	31,131	$	941	$	29,168	$	1,022

Liabilities:
Commodity derivatives	$	4,393	$	-	$	-	$	4,393
Interest-rate derivatives		46,623		-		13,053		33,570
Total	$	51,016	$	-	$	13,053	$	37,963

The Company’s Level 3 instruments include commodity derivative instruments, such as natural gas and fractionation processing spread swaps, and interest-rate swap derivatives for which the Company does not have sufficient corroborative market evidence to support classifying the asset or liability as Level 2, due to the limited market data available in the form of binding broker quotes or quoted prices for similar assets or liabilities in various markets. The financial assets and 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 non-binding broker quotes or third-party pricing service inputs to models used to measure the fair value of these assets and liabilities. The Company’s Level 2 instruments include natural gas swap derivatives that are valued based on models where significant inputs are observable and interest rate lock derivatives that are valued based on non-binding broker quotes which have been corroborated with observable market data. The Company’s Level 1 instruments consist of trading securities, related to a non-qualified deferred compensation plan, that are valued based on active market quotes.

The following table is a summary of the Company’s financial assets and liabilities that are measured at fair value on a recurring basis in accordance with Statement No. 157 using significant unobservable inputs (Level 3).

	Fair Value Measurements At March 31, 2008 Using Significant Unobservable Inputs (Level 3)
	Assets			Liabilities
	Commodity			Commodity			Interest-rate
	Derivatives			Derivatives			Derivatives
	(In thousands)

Beginning balance	$	1,320		$	(5,404	)	$	17,121
Total gains or losses (realized and unrealized):
Included in operating revenues		973			(2,784	)		-
Included in other comprehensive income		-			12,731			16,449
Purchases and settlements, net		(1,271	)		(150	)		-
Ending balance	$	1,022		$	4,393		$	33,570

The amount of total gains or losses for the period included in operating revenues attributable to the change in unrealized gains or losses relating to commodity derivative assets and commodity derivative liabilities still held at March 31, 2008 was a $297,000 loss and $3.2 million gain, respectively.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2008 Derivative Financial Instruments. In February 2008, the Company entered into three natural gas swap transactions which effectively established an average fixed index price at locations where it sells natural gas at a basis adjusted price of $8.28 per MMBtu related to 30,000 MMBtu/d for the period March 1, 2008 to December 31, 2008. In February 2008, for the period January 1, 2009 through December 31, 2009, the Company entered into an additional natural gas swap which effectively established a fixed index price for its natural gas at the basis adjusted price of $8.19 per MMBtu for the related period and has reduced its commodity price exposure related to 10,000 MMBtu/day. These natural gas swap derivative instruments qualify for hedge accounting treatment under Statement No. 133, and accordingly, changes in the fair value of the instruments will be recorded in other comprehensive income.

In March 2008, the Company entered into two fractionation processing spread swap arrangements, which effectively established a fixed price of $6.72 for 18,925 MMBtu/d of expected NGLs sales volumes for the period April 1, 2008 to December 31, 2008. In April 2008, the Company entered into a fractionation processing spread swap arrangement, which effectively establishes a fixed price of $7.10 for an additional 10,000 MMBtu/d of expected NGLs sales volumes for the period May 1, 2008 to December 31, 2008. In May 2008, the Company entered into various other fractionation processing spread swap arrangements, which have effectively established a weighted average fixed price of $6.76 for 15,000 MMBtu/d of expected NGLs sales volumes for the period January 1, 2009 to December 31, 2009. These fractionation spread swap derivative instruments do not qualify for hedge accounting treatment under Statement No. 133, and accordingly, changes in fair value of the instruments will be recorded in earnings.

There were no up-front costs associated with these new derivative instruments.

13. Regulation and Rates

The Company has commenced construction of an enhancement at its Trunkline LNG terminal. This infrastructure enhancement project, which was originally expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. Recent cost projections indicate the construction costs will likely be approximately $365 million, plus capitalized interest. The revised costs reflect increases in the quantities and cost of materials required, higher contract labor costs and an allowance for additional contingency funds, if needed. The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contract-based formula. The project is currently expected to be in operation in the second quarter of 2009. In addition, Trunkline LNG and BG LNG Services have agreed to extend the existing terminal and pipeline services agreements to coincide with the infrastructure enhancement project contract, which runs 20 years from the in-service date. Approximately $230.7 million and $178.3 million of costs are included in the line item Construction work-in-progress at March 31, 2008 and December 31, 2007, respectively.

Sea Robin filed a rate case with FERC in June 2007, requesting an increase in its maximum rates. Several parties have submitted protests to the rate increase filing with FERC. On July 30, 2007, FERC suspended the effectiveness of the filed rate increase until January 1, 2008. The filed rates were put into effect January 1, 2008, subject to refund. On February 14, 2008, at the request of the participants in the proceeding, the Chief Administrative Law Judge suspended the procedural schedule to facilitate the filing of a settlement. On April 29, 2008, Sea Robin submitted to FERC an Offer of Settlement that would resolve all issues in the proceeding.

14. Stockholders’ Equity

Dividends. On April 11, 2008, 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 28, 2008.

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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 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 natural gas liquids 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; and

·	dividends on preferred stock.

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

	Three Months Ended
	March 31,
	2008		2007
	(In thousands)
EBIT:
Transportation and storage segment	$	109,381	$	115,218
Gathering and processing segment		28,556		8,882
Distribution segment		30,301		33,545
Corporate and other		2,384		3,132
Total EBIT		170,622		160,777
Interest		50,701		52,185
Earnings before income taxes		119,921		108,592
Federal and state income tax expense		37,013		29,871
Net earnings		82,908		78,721
Preferred stock dividends		4,341		4,341

Net earnings available for common stockholders	$	78,567	$	74,380

Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. The Company’s $4.2 million increase in Net earnings available for common stockholders in the three-month period ended March 31, 2008 versus the same period in 2007 was primarily due to:

·	Higher EBIT contributions of $19.7 million from the Gathering and Processing segment primarily due to higher average realized natural gas and NGLs prices in the 2008 period versus the 2007 period; and

Decreased interest expense of $1.5 million largely due to lower interest expense related to Panhandle debt resulting from higher levels of interest costs capitalized attributable to higher capital expenditures and lower LIBOR-based rates in the 2008 period, partially offset by the impact of higher outstanding debt balances resulting from the $300 million 6.20% Senior Notes issued in October 2007.

These earnings improvements were partially offset by:

Higher income tax expense of $7.1 million primarily due to the higher federal and state effective income tax rate (EITR) of 31 percent in the 2008 period versus 28 percent in the 2007 period resulting from the decrease in tax benefit associated with the decrease in the dividends received deduction as a result of lower estimated dividends from the Company’s unconsolidated investment in Citrus;

Lower EBIT contributions of $5.8 million from the Transportation and Storage segment primarily due to lower equity earnings resulting from a $14.1 million nonrecurring gain from the settlement of a lawsuit with Spectra Energy LNG Sales, Inc. (Spectra), formerly known as Duke Energy LNG Sales, Inc., in the 2007 period, partially offset by higher EBIT contributions from Panhandle; and

·	Lower EBIT contributions of $3.2 million from the Distribution segment primarily due to higher operating expenses.

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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 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.

Historically, much of the Transportation and Storage segment’s business was conducted through long-term contracts with customers. Over the past several years, some customers within the segment have shifted to shorter term transportation services contracts. This shift, which can increase the volatility of revenues, is primarily due to changes in market conditions and competition with other pipelines, new supply sources, changing supply sources and volatility in natural gas prices. Average reservation revenue rates realized by the Company are dependent on certain factors, including but not limited to rate regulation, customer demand for reserved capacity, capacity sold levels for a given period and, in some cases, utilization of capacity. Commodity revenues are also dependent upon a number of variable factors including weather, storage levels, and customer demand for firm, interruptible and parking services. The majority of the Transportation and Storage segment revenues are related to firm capacity reservation charges.

The Company’s regulated transportation and storage businesses periodically 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 impact negatively the Company’s results of operations and financial condition.

The following table presents 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	2008		2007
	(In thousands)

Operating revenues	$	187,051	$	169,030

Operating expenses		60,692		56,280
Depreciation and amortization		25,061		20,709
Taxes other than on income
and revenues		8,649		7,795
Total operating income		92,649		84,246
Earnings from unconsolidated
investments		16,242		30,384
Other income, net		490		588
EBIT	$	109,381	$	115,218

Operating information:
Panhandle natural gas volumes transported
(in trillion British thermal units (TBtu))		401		371
Florida Gas natural gas volumes transported (TBtu) (1)		173		160

_______________

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

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Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. The $5.8 million EBIT reduction in the three-month period ended March 31, 2008 versus the same period in 2007 was primarily due to lower equity earnings of $14.1 million offset by a higher EBIT contribution from Panhandle totaling $8.3 million.

Equity earnings were lower by $14.1 million in 2008 versus 2007 primarily due to a $14.1 million nonrecurring gain recorded in the 2007 period related to the settlement of a lawsuit with Spectra.

Panhandle’s $8.3 million EBIT improvement was primarily due to the following items:

·	Higher operating revenues of $18 million primarily related to the following items:

Higher transportation reservation revenues of $11.8 million primarily due to the phased completion of the Trunkline Field Zone Expansion project during the period December 2007 to February 2008, reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand and utilization of contract capacity, and approximately $1.2 million of additional revenue attributable to the extra day in the 2008 leap year;

o	Higher other commodity transportation revenues of $4.2 million primarily due to a rate increase on Sea Robin and higher utilization on Sea Robin, net of refund provisions;

o	Higher storage revenues of $2.1 million due to increased contracted capacity;

o	Higher parking revenues of $1.6 million resulting from customer demand for parking services and market conditions; and

o	A $2 million decrease in LNG terminalling revenue due to lower volumes from decreased LNG cargoes during 2008.

These operating revenue increases were offset by higher operating expenses of $9.6 million primarily as the result of:

·	An increase in operation, maintenance and general expenses of $4.4 million primarily attributable to:

o	A $3.7 million increase in contract storage costs resulting from an increase in leased capacity;

o	A $2 million increase in insurance due to higher premiums;

o	A $900,000 increase in benefits primarily due to higher medical costs and defined contribution savings plan contributions;

o	A $500,000 increase in royalty service fees charged by Southern Union due to higher revenues;

o	A $2.3 million decrease in LNG power costs resulting from decreased cargoes during 2008; and

o	A $1.2 million decrease in fuel tracker costs primarily due to a net over-recovery in 2008;

Increased depreciation and amortization expense of $4.4 million due to a $536.5 million increase in property, plant and equipment placed in service after March 31, 2007. Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, including the compression modernization construction project and other capital expenditures; and

·	Higher taxes other than on income of $900,000 primarily due to higher property taxes attributable to higher qualifying operating income in the 2008 period versus the 2007 period upon which certain property tax assessments are based.

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 NGLs, and redelivering natural gas and NGLs to a variety of markets.

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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	2008			2007
	(In thousands)

Gross margin (1)	$	67,462		$	42,226
Operating expenses		22,949			17,668
Depreciation and amortization		15,470			14,587
Taxes other than on income and revenues		801			740
Total operating income		28,242			9,231
Earnings from unconsolidated investments		318			526
Other expense, net		(4	)		(875	)
EBIT	$	28,556		$	8,882


Operating information:
Volumes
Avg natural gas processed (MMBtu/d)		408,082			440,919
Avg NGLs produced (gallons/d)		1,336,032			1,359,049
Avg natural gas wellhead (MMBtu/d)		623,149			590,198
Natural gas sales (MMBtu)		24,159,245			29,656,605
NGLs sales (gallons)		154,660,401			115,536,360

Average Pricing
Realized natural gas ($/MMBtu)	$	7.79		$	6.35
Realized NGLs ($/gallon)		1.42			0.87
Natural Gas Daily WAHA ($/MMBtu)		8.00			6.45
Natural Gas Daily El Paso ($/MMBtu)		7.92			6.34
Estimated plant processing spread ($/gallon)		0.69			0.29

________________

(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.

Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. The $19.7 million EBIT improvement in the three-month period ended March 31, 2008 versus the same period in 2007 was primarily due to the following items:

·	Gross margin was higher by $25.2 million as the result of:

o	Higher market-driven average realized natural gas and NGLs prices of $7.79 per MMBtu and $1.42 per gallon in the 2008 period versus $6.35 per MMBtu and $0.87 per gallon in the 2007 period, respectively;

o	Favorable impact of $4.9 million of net unrealized hedging gains resulting from the recognition of a $3.1 million net gain in the 2008 period versus a $1.8 million net loss in the 2007 period; and

o	Favorable gross margin impact of lower levels of fuel, flare and unaccounted for gas losses in the 2008 period versus the unusually high levels experienced in the 2007 period due to capacity and treating limitations and a one-time event experienced at the Mi Vida facility.

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These EBIT increases were offset by the following items:

·	Operating expenses were higher by $5.3 million primarily due to:

o	Higher chemical and lubricants costs of $1.2 million primarily due to scheduled maintenance of the Company’s Jal facility in January 2008; and

o	Increases in employee labor and benefit costs and contractor services costs of $1 million and $1.4 million, respectively, primarily resulting from competitive forces currently experienced within the midstream energy industry; and

·	Depreciation and amortization expenses were higher by $900,000 primarily due to a $66 million increase in property, plant and equipment placed in service after March 31, 2007.

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 Company’s utility operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. The Company’s utility 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 Missouri Public Service Commission approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 87 percent of its total customers and approximately 66 percent of its margin revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

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

	Three Months Ended
	March 31,
Distribution Segment	2008			2007
	(In thousands)

Net operating revenues (1)	$	68,111		$	68,002

Operating expenses		27,061			23,281
Depreciation and amortization		7,572			7,618
Taxes other than on income
and revenues		2,989			3,163
Total operating income		30,489			33,940
Other income (expenses), net		(188	)		(395	)
EBIT	$	30,301		$	33,545

Operating Information:
Gas sales volumes (MMcf)		33,135			29,527
Gas transported volumes (MMcf)		9,634			8,538

Weather – Degree Days: (2)
Missouri Gas Energry service territories		2,921			2,461
New England Gas Company service territories		2,654			2,801

________________

(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.

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Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. The $3.2 million EBIT reduction in the three-month period ended March 31, 2008 versus the same period in 2007 was primarily due to the net impact of the following incurred operating expenses:

·	Establishment of an environmental remediation reserve of approximately $2.4 million resulting from site investigation evaluations completed during the first quarter of 2008; and

·	Higher customer uncollectible accounts of approximately $700,000 primarily resulting from higher natural gas costs billed to customers.

Interest Expense

Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. Interest expense was $1.5 million lower in the three-month period ended March 31, 2008 versus the same period in 2007 primarily due to:

· Lower interest expense of $1 million related to Panhandle debt primarily due to the impact of the higher level of interest costs capitalized attributable to higher capital expenditures and lower LIBOR-based rates in the 2008 period, partially offset by the impact of higher outstanding debt balances resulting from the $300 million 6.20% Senior Notes issued in October 2007;

· Lower interest expense of $900,000 associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2008 compared to 2007; and

·	Impact of higher net interest expense of $200,000 associated with the remarketing of the $100 million 4.375% Senior Notes in February 2008, which were replaced with the higher interest rate $100 million 6.089% Senior Notes.

Federal and State Income Taxes

Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007.

The EITR for the three-month periods ended March 31, 2008 and 2007 was 31 percent and 28 percent, respectively. The increase in the EITR was primarily due to a decrease in the tax benefit associated with the dividends received deduction as a result of lower estimated dividends from the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2008 and 2007, the tax benefit of the dividends received deduction was $9 million and $11.5 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, 2007.

Cash generated from internal operations constitutes the Company’s primary source of liquidity. The Company’s $540.9 million working capital deficit at March 31, 2008 is primarily composed of $425 million of debt maturing in August 2008, which is expected to be funded with new capital market debt or bank financings. Additional sources of liquidity include use of available credit facilities and may include various equity offerings, project 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. Acquisitions, which generally require a substantial increase in expenditures, and related financings also affect the Company's combined results. Future acquisitions or related financings or refinancings may involve the issuance of shares of the Company's common stock, which could have a dilutive effect on the then-current stockholders of the Company.

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Operating Activities

Three-month period ended March 31, 2008 versus the three-month period ended March 31, 2007. Cash flows provided by operating activities were $239.6 million for the three months ended March 31, 2008 compared with cash flows provided by operating activities of $171.8 million for the same period in 2007. Cash flows provided by operating activities before changes in operating assets and liabilities for the 2008 period were $165.5 million compared with $166.1 million for the 2007 period. Changes in operating assets and liabilities provided cash of $74 million in 2008 and $5.6 million in 2007, resulting in an increase in cash of $68.4 million in 2008 compared to 2007. The $68.4 million increase in cash is primarily due to increases in accounts payable balances caused by higher gas purchases costs. This increase in natural gas purchases costs was due to a colder winter season in 2008 versus 2007 and higher natural gas prices.

Investing Activities

Summary

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

Cash flows used in investing activities in the three-month periods ended March 31, 2008 and 2007 were $215.6 million and $118.1 million, respectively. The $97.5 million increase in invested cash is primarily due to the $150.8 million of increased capital spending in the Transportation and Storage segment, partially offset by the $49.3 million in working capital adjustment payments made in the 2007 period related to the 2006 sales of certain distribution assets.

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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	2008		2007
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	48,506	$	17,632
Trunkline Field Zone Expansion		59,004		7,572
East End Enhancement		29,138		3,629
Compression Modernization		19,714		3,200
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance		25,804		14,775
Total		182,166		46,808

Gathering and Processing Segment		17,469		12,356

Distribution Segment
Missouri Safety Program		2,395		1,122
Other, primarily system replacement
and expansion		3,309		5,992
Total		5,704		7,114

Corporate and other		1,220		634

Total (1)	$	206,559	$	66,912

____________________

(1) Includes net capital accruals totaling $(21.8) million and $(3.1) million for the three-month periods ended March 31, 2008 and 2007, respectively.

Principal Capital Expenditure Projects. The Company’s capital expenditure programs through 2008 are expected to be funded primarily by cash flows from operations and from financings more fully described in the Financing Activities section. During the first quarter of 2008, the Company completed construction of its Trunkline system Field Zone Expansion project for a total estimated cost of approximately $255 million, plus capitalized interest. The Company’s Trunkline LNG terminal infrastructure enhancement project, with a current estimated construction cost of $365 million, plus capitalized interest, is still expected to be placed into operation in the second quarter of 2009. The Company’s East End Enhancement project cost estimate has been increased from $125 million to $135 million, plus capitalized interest, primarily due to delays associated with construction issues.

Financing Activities

Summary

Cash flows provided by financing activities were $3 million for the three-month period ended March 31, 2008 compared with cash used of $58.7 million for the same period in 2007. The $61.7 million increase in financing cash inflows was primarily due to the remarketing of equity units in 2008, partially offset by higher payments on the revolving credit facilities and higher common stock dividends in the 2008 period versus the 2007 period.

Retirement of Debt Obligations

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believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital and debt markets, current economic and capital market conditions and market expectations regarding the Company's future earnings and cash flows, that it will be able to refinance and/or retire these obligations under acceptable terms prior to their maturity. There can be no assurance, however, that the Company will be able to achieve acceptable refinancing terms in any negotiation of new capital market debt or bank financings. Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company's inability to do so would cause a material adverse effect on the Company's financial condition and liquidity.

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.

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, 2007, in addition to the 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 did not have a material amount of assets and liabilities measured using significant unobservable inputs (e.g. Statement No. 157 level 3 assets and liabilities) as a percentage of the total assets and liabilities measured at fair value. Although the Company does not have sufficient corroborative market evidence to support classifying certain level 3 assets and liabilities within level 2, the Company does not utilize significant unobservable inputs that are based on its own internal assumptions within these level 3 assets and liabilities. Rather, the Company utilizes non-binding broker quotes or third-party pricing services in determining their period-end fair value. The results of realized and unrealized gains (losses) related to level 3 assets and liabilities did not have a material effect on the Company’s results of operations, liquidity or capital resources during the three-month period ended March 31, 2008.

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, 2008, the interest rate on 88 percent of the Company’s long-term debt was fixed after considering the impact of interest rate swaps.

At March 31, 2008, $33.6 million is included in Deferred credits in the Condensed Consolidated Balance Sheet related to the fixed-rate interest rate swaps on the $455 million Term Loan due 2012.

At March 31, 2008, a 100 basis point move in the annual interest rate on all outstanding floating-rate long-term debt would increase the Company’s interest payments by approximately $400,000 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.

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The Company also enters into treasury rate locks 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. The Company accounts for the treasury rate locks as cash flow hedges. At March 31, 2008, $13.1 million was included in Other current liabilities in the Condensed Consolidated Balance Sheet related to the treasury rate locks. The Company has treasury rate locks with an aggregate notional amount of $300 million outstanding as of March 31, 2008 to hedge the changes in cash flows of anticipated interest payments from changes in treasury rates prior to the issuance of new debt instruments.

The change in exposure to loss in earnings and cash flows related to interest rate risk for the three-month period ended March 31, 2008 is not material to the Company.

Commodity Price Risk

Gathering and Processing Segment. The Company markets natural gas and NGLs in its Gathering and Processing segment and manages associated commodity price risks using both economic and accounting hedge derivative financial instruments. These instruments involve not only the risk of transacting with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations. The Company is required to record its commodity derivative financial instruments at fair value, which is determined by commodity exchange prices, over-the-counter quotes, volatility, time value, counterparty credit 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 NGLs, the Company uses a combination of puts, NGL gross processing spread puts, fixed-price physical forward sales contracts, exchange-traded futures and options, and fixed or floating index and basis swaps to manage commodity price risk. These derivative financial instruments allow the Company to preserve value and protect margins because changes in the value of the derivative financial instruments are highly effective in offsetting changes in the physical market 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 its contractual arrangements associated with gas processing services it provides. The Company utilizes various economic hedge techniques to manage its price exposure of Company owned volumes, including processing spread put optionss and natural gas swaps. 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 FF&U efficiency levels;
Impact of commodity prices in general;
Lower than expected recovery of NGLs from the residue gas stream; and
Lower than expected recovery of natural gas volumes to be processed.

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The following table summarizes SUGS' principal commodity hedge portfolio as of March 31, 2008 (all hedges are settled monthly). The portfolio was developed based upon recent operating conditions and resulting expected equity NGLs sales volumes equivalent of approximately 40,000 MMBtu/day.

					Volumes (MMBtu/d)
Instrument Type	Index	Hedge Type	Average Fixed Price (per MMBtu)		2008		2009		Fair Value Asset (Liability)

Natural Gas
Swap	IF - Waha	Accounting	$	8.01		5,525		-	$	(2,268,664	)
Swap	IF - El Paso Permian	Accounting		8.01		4,475		-		(1,837,515	)
Swap	Gas Daily - Waha	Accounting		8.42		11,050		-		(3,276,246	)
Swap	Gas Daily - Waha	Accounting		8.19		-		5,525		(1,406,127	)
Swap	Gas Daily - El Paso Permian	Accounting		8.42		8,950		-		(2,653,611	)
Swap	Gas Daily - El Paso Permian	Accounting		8.19		-		4,475		(1,138,899	)
			Total Swaps			30,000		10,000	$	(12,581,062	)

Processing Spread
Put	IF - Waha	Economic	$	8.15		6,119		-	$	3,589,595
Put	IF - El Paso Permian	Economic		8.15		4,956		-		2,939,054
			Total Puts			11,075		-	$	6,528,649

Swap	Gas Daily - Waha	Economic		6.72		10,456		-	$	982,627
Swap	Gas Daily - El Paso Permian	Economic		6.72		8,469		-		795,883
			Total Swaps			18,925		-	$	1,778,510

There were no up-front costs associated with these new derivative instruments.

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Transportation and Storage Segment. The Company is exposed to commodity price risk as its interstate pipelines collect natural gas from its customers for operations or as part of their fee for services provided. When the amount of natural gas utilized in operations by these pipelines differs from the amount provided by their customers, the pipelines may use natural gas from inventory or could have to buy or sell natural gas to cover these operational needs and thus have some exposure to commodity price risk. At March 31, 2008, there were no hedges in place in respect to natural gas price risk from its interstate pipeline operations.

Distribution Segment Economic Hedging Activities. The Company has entered into natural gas commodity swaps to mitigate price volatility of natural gas passed through to utility 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 Condensed Consolidated Balance Sheet. As of March 31, 2008 and December 31, 2007, the fair values of the contracts, which expire at various times through March 2010, are included in the Condensed Consolidated Balance Sheet as assets and liabilities, respectively, with matching adjustments to deferred cost of gas of $28.9 million and $22.3 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 Securities Exchange Act of 1934, as amended (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 Chief Executive Officer (CEO) and Chief Financial Officer (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, 2008.

Changes in Internal Controls.

Management’s assessment of internal control over financial reporting as of December 31, 2007 was included in Southern Union’s Annual Report on Form 10-K filed on February 29, 2008.

There have been no changes in internal control over financial reporting that occurred during the first three months of 2008 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 products, expenses, interest rates, the outcome of contingencies, such as legal proceedings, and financial results.

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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 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 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 increased 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.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in PART I, ITEM 1. Financial Statements (Unaudited), Note 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, 2007.

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, 2007.

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors previously disclosed in the Company’s Form 10-K filed with the SEC on February 29, 2008.

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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, 2008 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.)

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet be Purchased Under the Publicly Announced Plans or Programs
January 1, 2008 through January 31, 2008		3,333	$	29.42		-	$	-
February 1, 2008 through February 29, 2008		325		27.49		-		-
March 1, 2008 through March 31, 2008		23,363		23.99		-		-
Total		27,021	$	24.70		-	$	-

___________________

(1)

The total number of shares purchased includes: (i) the surrender to the Company of 3,210 shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock awards and (ii) 23,811 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, 2008 was appropriately reported.

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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 filed on March 16, 2006 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.)

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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)

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.)

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10(b)

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 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(c)

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(d)

Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein dated September 29, 2005. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 5, 2005 and incorporated herein by reference.)

10(e)

First Amendment to the Fourth Amended and Restated Revolving Credit Agreement between Southern Union Company and the Banks named therein. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on March 6, 2006 and incorporated herein by reference.)

10(f)

Second Amendment to Fourth Amended and Restated Revolving Credit Agreement dated September 29, 2005, among the Company, as borrower, and the lenders party there. (Filed as Exhibit 10.1 to Southern Union’s Current Report on Form 8-K filed on October 23, 2007 and incorporated herein by reference.)

10(g)

Form of Indemnification Agreement between Southern Union Company and each of the Directors of Southern Union Company. (Filed as Exhibit 10(i) to Southern Union’s Annual Report on Form 10-K for the year ended December 31, 1986 and incorporated herein by reference.)

10(h)

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(i)

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(j)

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 for the quarter ended September 30, 2007 and incorporated herein by reference.)

10(k)

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(l)

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(m)

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(n)

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.)

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10(o)

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(p)

Southern Union Company Pennsylvania Division Stock Incentive Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36146, filed on May 3, 2000 and incorporated herein by reference.)

10(q)

Southern Union Company Pennsylvania Division 1992 Stock Option Plan. (Filed as Exhibit 4 to Form S-8, SEC File No. 333-36150, filed on May 3, 2000 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)

Capital Stock Agreement dated June 30, 1986, as amended April 3, 2000 ("Agreement"), among El Paso Energy Corporation (as successor in interest to Sonat, Inc.); CrossCountry Energy, LLC (assignee of Enron Corp., which is the successor in interest to InterNorth, Inc. by virtue of a name change and successor in interest to Houston Natural Gas Corporation by virtue of a merger) and Citrus Corp. (Filed as Exhibit 10(p) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)

10(t)

Certificate of Incorporation of Citrus Corp. (Filed as Exhibit 10(q) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)

10(u)

By-Laws of Citrus Corp., filed herewith. (Filed as Exhibit 10(r) to Southern Union’s Form 10-K dated March 1, 2007 and incorporated herein by reference.)

Ratio of earnings to fixed charges.

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.)

Subsidiaries of the Registrant. (Filed as Exhibit 21 to Southern Union’s Annual Report on Form 10-K filed on February 29, 2008 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.

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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 9, 2008	By /s/ GEORGE E. ALDRICH
	George E. Aldrich Vice President and Controller (authorized officer and principal accounting officer)