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, 2007

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(b) of the Act:

Title of each class	Name of each exchange in which registered
Common Stock, par value $1 per share	New York Stock Exchange
7.55% Depositary Shares	New York Stock Exchange
5.00% Corporate Units	New York Stock Exchange

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer”

in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer P Accelerated filer  Non-accelerated filer ____

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 4, 2007 was 119,839,739.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

March 31, 2007

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.	32
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	40
ITEM 4. Controls and Procedures.	41
PART II. OTHER INFORMATION:
ITEM 1. Legal Proceedings.	42
ITEM 1A. Risk Factors.	43
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.	43
ITEM 3. Defaults Upon Senior Securities.	43
ITEM 4. Submission of Matters to a Vote of Security Holders.	43
ITEM 5. Other Information.	44
ITEM 6. Exhibits.	44
SIGNATURES	48

1

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,
	2007			2006
	(In thousands, except per share amounts)
Operating revenues (Note 15)	$	780,232		$	547,166
Operating expenses:
Cost of gas and other energy		483,085			306,602
Revenue-related taxes		17,019			16,217
Operating, maintenance and general		95,195			78,777
Depreciation and amortization		43,464			30,865
Taxes, other than on income and revenues		11,875			11,858
Total operating expenses		650,638			444,319
Operating income		129,594			102,847
Other income (expenses):
Interest expense		(52,185	)		(42,221	)
Earnings from unconsolidated investments		30,896			11,566
Other, net		287			37,093
Total other income (expenses), net		(21,002	)		6,438
Earnings from continuing operations before income taxes		108,592			109,285
Federal and state income tax expense (Note 12)		29,871			35,867
Net earnings from continuing operations		78,721			73,418
Discontinued operations (Note 16):
Earnings from discontinued operations before income taxes		-			38,009
Federal and state income tax expense (Note 12)		-			13,480
Net earnings from discontinued operations		-			24,529
Net earnings		78,721			97,947
Preferred stock dividends		(4,341	)		(4,341	)
Net earnings available for common stockholders	$	74,380		$	93,606
Net earnings available for common stockholders from
continuing operations per share:
Basic	$	0.62		$	0.62
Diluted	$	0.62		$	0.60
Net earnings available for common stockholders per share:
Basic	$	0.62		$	0.84
Diluted	$	0.62		$	0.82
Dividends declared on common stock per share	$	0.10		$	0.10
Weighted average shares outstanding (Note 5):
Basic		119,790			111,668
Diluted		120,277			114,674

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

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	March 31,			December 31,
	2007			2006
	(In thousands)
Current assets:
Cash and cash equivalents	$	729		$	5,751
Accounts receivable, net of allowances of
$6,083 and $4,830, respectively		313,957			298,231
Accounts receivable – affiliates		9,135			3,546
Inventories (Note 4)		174,542			241,137
Gas imbalances - receivable		108,882			69,877
Prepayments and other assets		44,377			72,317
Total current assets		651,622			690,859
Property, plant and equipment:
Plant in service		5,086,817			5,025,631
Construction work in progress		177,768			178,935
		5,264,585			5,204,566
Less accumulated depreciation and amortization		(659,272	)		(620,139	)
Net property, plant and equipment		4,605,313			4,584,427
Deferred charges:
Regulatory assets (Note 6)		70,595			65,865
Deferred charges		60,110			61,602
Total deferred charges		130,705			127,467
Unconsolidated investments (Note 7)		1,248,557			1,254,749
Goodwill		89,227			89,227
Other		33,820			36,061
Total assets	$	6,759,244		$	6,782,790

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	March 31,			December 31,
	2007			2006
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
120,892 shares issued at March 31, 2007	$	120,892		$	120,718
Preferred stock, no par value; 6,000 shares authorized;
920 shares issued at March 31, 2007		230,000			230,000
Premium on capital stock		1,777,901			1,775,763
Less treasury stock: 1,060 and 1,059
shares, respectively, at cost		(27,724	)		(27,708	)
Less common stock held in trust: 771
and 863 shares, respectively		(14,689	)		(14,628	)
Deferred compensation plans		14,752			14,691
Accumulated other comprehensive loss		(8,221	)		(901	)
Retained earnings (deficit)		14,876			(47,527	)
Total stockholders' equity		2,107,787			2,050,408
Long-term debt obligations (Note 10)		3,032,170			2,689,656
Total capitalization		5,139,957			4,740,064
Current liabilities:
Long-term debt and capital lease obligation
due within one year (Note 10)		111,806			461,011
Notes payable (Note 10)		95,000			100,000
Accounts payable and accrued liabilities		170,284			300,762
Federal, state and local taxes payable		39,053			30,828
Accrued interest		43,344			46,342
Customer deposits		13,732			14,670
Deferred gas purchases		16,603			15,551
Gas imbalances - payable		195,523			146,995
Other		95,569			84,665
Total current liabilities		780,914			1,200,824
Deferred credits		201,274			224,725
Accumulated deferred income taxes		637,099			617,177
Commitments and contingencies (Note 14)
Total stockholders' equity and liabilities	$	6,759,244		$	6,782,790

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2007			2006
	(In thousands)
Cash flows provided by operating activities:
Net earnings	$	78,721		$	97,947
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		43,464			32,768
Amortization of debt premium		(667	)		(637	)
Deferred income taxes		24,294			27,788
Provision for bad debts		67			6,195
Impairment of assets		-			6,500
Amortization of debt issuance costs		1,037			1,608
Loss (gain) on derivatives		843			(37,182	)
Earnings from unconsolidated investments, net of cash distributions		16,704			(11,566	)
Other		1,682			(1,855	)
Changes in operating assets and liabilities, net of acquisitions		(43,670	)		23,332
Net cash flows provided by operating activities		122,475			144,898
Cash flows (used in) provided by investing activities:
Additions to property, plant and equipment		(70,034	)		(52,426	)
Acquisitions of operations, net of cash received		-			(1,533,203	)
Other		1,238			2,987
Net cash flows used in investing activities		(68,796	)		(1,582,642	)
Cash flows provided by (used in) financing activities:
Increase (decrease) in bank overdraft		(31,398	)		(39,652	)
Issuance costs of debt		(525	)		(9,195	)
Issuance of long-term debt		455,000			-
Dividends paid on common stock		(11,961	)		-
Dividends paid on preferred stock		(4,341	)		(4,341	)
Repayment of debt obligation		(462,289	)		-
Issuance of bridge loan		-			1,600,000
Net payments under revolving credit facilities		(5,000	)		(115,000	)
Proceeds from exercise of stock options		1,558			5,257
Tax benefit on stock option exercises		255			1,446
Other		-			1,871
Net cash flows provided by (used in) financing activities		(58,701	)		1,440,386
Change in cash and cash equivalents		(5,022	)		2,642
Cash and cash equivalents at beginning of period		5,751			16,938
Cash and cash equivalents at end of period	$	729		$	19,580

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common			Preferred		Premium						Common			Deferred			Accumulated						Total
	Stock			Stock,		on			Treasury			Stock			Compen-			Other			Retained			Stock-
		$1 Par		No Par		Capital			Stock,			Held			sation			Comprehensive			Earnings			holders'
		Value		Value		Stock			at cost			In Trust			Plans			Income (Loss)			(Deficit)			Equity
										(In thousands)
Balance December 31, 2006	$	120,718	$	230,000	$	1,775,763		$	(27,708	)	$	(14,628	)	$	14,691		$	(901	)	$	(47,527	)	$	2,050,408
Comprehensive income (loss):
Net earnings		-		-		-			-			-			-			-			78,721			78,721
Unrealized loss on hedging
activities, net of tax		-		-		-			-			-			-			(3,167	)		-			(3,167	)
Change in fair value of hedging
derivatives, net of tax		-		-		-			-			-			-			(4,727	)		-			(4,727	)
Recognized actuarial gain (loss) and
prior service credit (cost), net of tax		-		-		-			-			-			-			574			-			574
Comprehensive income																								71,401
Preferred stock dividends		-		-		-			-			-			-			-			(4,341	)		(4,341	)
Cash dividends declared		-		-		-			-			-			-			-			(11,977	)		(11,977	)
Share-based compensation		-		-		499			-			-			-			-			-			499
Restricted stock issuances		92		-		(92	)		(16	)		-			-			-			-			(16	)
Exercise of stock options		82		-		1,731			-			-			-			-			-			1,813
Contributions to Trust		-		-		-			-			(372	)		372			-			-			-
Disbursements from Trust		-		-		-			-			311			(311	)		-			-			-
Balance March 31, 2007	$	120,892	$	230,000	$	1,777,901		$	(27,724	)	$	(14,689	)	$	14,752		$	(8,221	)	$	14,876		$	2,107,787

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 outstanding.

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

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements of 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 twelve months ended December 31, 2006, included in the Company’s Form 10-K filed with the SEC. The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with GAAP and reflect adjustments that are, in the opinion of management, necessary for a fair statement of results for the interim period. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Due to the seasonal nature of the Company’s operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year. Certain prior period amounts have been reclassified to conform with the current period presentation.

1. Description of Business

Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the gathering, processing, transportation, storage and distribution of natural gas in the United States. The Company operates in three reportable segments: Transportation and Storage, Gathering and Processing, and Distribution. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest 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, transmission, 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. The Company’s discontinued operations in 2006 related to its former PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.

2. New Accounting Principles

Accounting Principles Recently Adopted.

FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109” (FIN 48): Issued by the Financial Accounting Standards Board (FASB) in June 2006, the Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company’s consolidated financial statements have not been materially impacted by the adoption of FIN 48 as of January 1, 2007. See Note 12 - Taxes on Income.

Accounting Principles Not Yet Adopted.

FASB Statement No. 157, “Fair Value Measurements”: Issued by the 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. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

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

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2007. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

3. Accumulated Other Comprehensive Income (Loss)

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

	Three Months Ended March 31,
Other Comprehensive Income (Loss)	2007			2006
	(In thousands)
Net Earnings	$	78,721		$	97,947
Other Comprehensive Income (Loss) Adjustments:
Reclassification of unrealized gain (loss) on interest rate hedges
into earnings, net of tax of $(3) and $(34), respectively		(1,045	)		(38	)
Change in fair value of commodity hedges, net of tax of $(2,868)
and $(3,329), respectively		(4,727	)		(5,599	)
Reclassification of unrealized gain (loss) on commodity hedges
into earnings, net of tax of $(1,287) and $0, respectively		(2,122	)		-
Reclassification of actuarial gain (loss) and prior service credit (cost) relating to pension
and other postretirement benefits into earnings, net of tax of $(77) and $0, respectively		574			-
Total other comprehensive income (loss)		(7,320	)		(5,637	)
Total comprehensive income	$	71,401		$	92,310

The table below provides an overview of the components in Accumulated other comprehensive income (loss) as of the periods indicated:

	March 31,			December 31,
Components in Accumulated Other Comprehensive Income (Loss)	2007			2006
	(In thousands)
Interest rate hedges, net	$	(3,357	)	$	(2,312	)
Commodity hedges, net		(1,573	)		5,276
Benefit Plans:
Net actuarial loss and prior service costs, net - pensions		(25,358	)		(26,678	)
Net actuarial gain and prior service credit, net - other postretirement benefits		22,067			22,813
Total Accumulated other comprehensive loss, net of tax	$	(8,221	)	$	(901	)

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, 2007 was $125.8 million, or 17,534,944 million British thermal units (MMBtu), of which $13.2 million was classified as non-current. Gas held for operations at December 31, 2006 was $129.4 million, or 20,965,000 MMBtu, of which $14.9 million was classified as non-current. Materials and supplies inventories in the Transportation and Storage segment were $13.4 million and $13.2 million at March 31, 2007 and December 31, 2006, 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 value. Materials and supplies in the Gathering and Processing segment, primarily comprised of compressor components and parts, were $6.5 million and $6.9 million at March

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

31, 2007 and December 31, 2006, 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, 2007 and December 31, 2006 was $38.5 million and $103.5 million, respectively, and consisted of 5,403,000 MMBtu and 14,702,000 MMBtu, respectively. Materials and supplies inventories in the Distribution segment were $3.5 million and $3.7 million at March 31, 2007 and December 31, 2006, respectively.

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, stock appreciation rights and convertible equity units. 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,
	2007		2006
	(In thousands)
Weighted average shares outstanding - Basic		119,790		111,668
Add assumed vesting of restricted stock		26		95
Add assumed conversion of equity units		-		2,264
Add assumed exercise of stock options
and stock appreciation rights		461		647
Weighted average shares outstanding - Dilutive		120,277		114,674

There were nil and 36,001 anti-dilutive options outstanding for the three months ended March 31, 2007 and 2006, respectively.

6. Regulatory Assets

The Company records regulatory assets and liabilities with respect to its Distribution segment operations in accordance with FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation (Statement No. 71). The following table provides a summary of regulatory assets at the dates indicated:

	March 31,		December 31,
Regulatory Assets	2007		2006
	(In thousands)
Pension and Postretirement Benefits	$	35,419	$	33,969
Environmental		16,361		15,571
Missouri Safety Program		7,950		8,751
Other		10,865		7,574
	$	70,595	$	65,865

The Company’s regulatory assets at March 31, 2007 relating to Distribution segment operations that are being recovered through current rates totaled $43.7 million. The remaining recovery period associated with these assets ranged from nine months to 90 months. The Company’s regulatory assets at December 31, 2006 relating to Distribution segment operations that are being recovered through current rates totaled $30.7 million. The remaining recovery period associated with these assets ranged from twelve months to 93 months.

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

7. Unconsolidated Investments

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

	March 31,		December 31,
Unconsolidated Investments	2007		2006
	(In thousands)
Equity investments:
Citrus	$	1,226,321	$	1,233,172
Other		21,461		20,802
Investments at cost		775		775
	$	1,248,557	$	1,254,749

Equity Investments. Unconsolidated investments at March 31, 2007 and December 31, 2006 included the Company’s 50 percent, 50 percent, 29 percent and 49.9 percent investments in Citrus Corp. (Citrus), Grey Ranch Plant, LP, Lee 8 Partnership and PEI Power Corporation, 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.

Citrus. On December 1, 2006, the Company completed a series of transactions that resulted in the Company becoming the sole owner of 100 percent of CCE Holdings, LLC (CCE Holdings), whose principal remaining asset was its 50 percent interest in Citrus. The Company’s equity investment balance in Citrus includes amounts in excess of its share of the underlying equity of the investee of $607 million and $585.6 million as of March 31, 2007 and December 31, 2006, respectively. The equity goodwill includes an allocation of $208.4 million of excess purchase cost associated with the increased interest in Citrus effectively acquired on December 1, 2006. The combined fair value amount recorded in excess of the Company’s 50 percent share of the underlying Citrus equity at March 31, 2007 was as follows:

	Excess Purchase Costs			Amortization Period
	(In thousands)
Property, plant and equipment	$	2,885		40 years
Capitalized software		1,478		5 years
Long-term debt (1)		(80,204	)	4-20 years
Deferred taxes (1)		(6,883	)	40 years
Other net liabilities		(2,719	)	N/A
Goodwill (2)		664,609		N/A
Sub-total		579,166
Accumulated, net accretion to equity earnings		27,806
Net investment in excess of underlying equity	$	606,972

____________________

(1)   Accretion of this amount increases equity earnings and accumulated net accretion.

(2)   The Company expects to have a tax basis in all of the equity goodwill.

Dividends. During the three-month period ended March 31, 2007, Citrus paid dividends of $47.6 million to the Company.  No dividends were received in the three-month period ended March 31, 2006 associated with the Company's equity investments.

10

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, 2007				March 31, 2006
			Other Equity		CCE						Other Equity
	Citrus		Investments		Holdings (1)						Investments
			(In thousands)
Income Statement Data:
Revenues	$	109,038	$	2,215	$	-				$	1,019
Operating income (loss)		56,875		794		(1,572	)				246
Equity earnings		-		-		13,858		(2	)		-
Income from discontinued
operations		-		-		17,877		(3	)		-
Net income		40,141		1,692		23,762					214

_____________________

(1) CCE Holdings became a wholly-owned subsidiary on December 1, 2006.

(2) Represents equity earnings of CCE Holdings in Citrus.

(3) Income from discontinued operations for CCE Holdings relates primarily to the operations of

     Transwestern.

Contingent Matters Potentially Impacting Southern Union Through the Company’s Investment in Citrus. The following updated information should be read in conjunction with the related information included in Note 9 - Unconsolidated Investments in the Company’s Form 10-K for the year ended December 31, 2006.

Environmental Matters. Florida Gas Transmission Company, LLC (Florida Gas), which is the principal entity owned by Citrus, is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted from past releases of hydrocarbons and chlorinated compounds. Florida Gas is implementing a program to remediate such contamination. 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.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (U.S. EPA) Spill Prevention, Control and Countermeasures (SPCC) program. The Company is currently reviewing the impact of these modifications to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot reasonably be estimated 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.

Goodwill Evaluation. Goodwill associated with the Company’s equity investment in Citrus accounted for under Accounting Principles Board Opinion 18, The Equity Method of Accounting for Investments in Common Stock (APB 18), was approximately $664.6 million and $642.2 million at March 31, 2007 and December 31, 2006, respectively. The amount recorded for goodwill includes final purchase price allocation adjustments.

Regulatory Assets and Liabilities. Florida Gas is subject to regulation by certain state and federal authorities. Florida Gas has accounting policies that conform to Statement No. 71 and are in accordance with the accounting requirements and ratemaking practices of applicable regulatory authorities. Management’s assessment for Florida Gas of the probability of its recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, Florida Gas ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from their condensed consolidated balance sheet, resulting in an impact to the Company’s share of its equity

11

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

earnings. Florida Gas’ regulatory asset and liability balances at March 31, 2007 were $18.8 million and $11.1 million, respectively. Florida Gas’ regulatory asset and liability balances at December 31, 2006 were $19.3 million and $14.3 million, respectively.

Federal Pipeline Integrity Rules. On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (HCAs). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to have identified HCAs along their pipelines by December 2004 and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004. Operators must rank the risk of their pipeline segments containing HCAs and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. All systems operated by the Company will be compliant with the rule; however, while identification and location of all HCAs has been completed, it is not practicable to determine the total scope of required remediation activities prior to completion of the assessments and inspections. For Florida Gas, the required modifications and inspections are preliminarily estimated to be in the range of approximately $18 million to $23 million per year through 2009, inclusive of remediation costs.

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages that may, over the next ten years, impact one or more of Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way. Florida Gas is currently considering its options relating to the first phase of the turnpike project, which include replacement of approximately 11.3 miles of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in Florida. Estimated cost of such replacement would be $110.5 million. 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 right-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 right-of-way needed for relocation of the pipelines and for 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 FDOT in the Seventeenth Judicial Circuit, Broward County, Florida, seeking relief with respect to three specific sets of FDOT 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. By motion dated March 2, 2007, the FDOT/FTE moved to transfer venue to Orange County, Florida, where Florida Gas had filed, and subsequently voluntarily dismissed, a related suit against the FDOT/FTE in 2005. The motion was denied on April 27, 2007. On April 30, 2007, the FDOT/FTE filed a motion for reconsideration. On April 24, 2007, the FDOT/FTE filed a complaint against Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, which seeks a declaratory judgment that under the existing agreements Florida Gas is liable for the costs of relocation associated with such projects and is not entitled to certain other rights. 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 Federal Energy Regulatory Commission (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.

Citrus Trading Litigation. On January 29, 2007, Citrus Trading Corp. (Citrus Trading), Citrus, Southern Union and El Paso Corporation (collectively, Citrus Parties) entered into a settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly known as Duke Energy LNG Sales, Inc. (Duke), and its parent company

12

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Spectra Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100 million to Citrus Trading. The litigation related to a natural gas purchase contract between Citrus Trading and Duke that had been terminated in 2003. Citrus recorded a net gain of $15 million in the first quarter of 2007, $7.5 million of which is included in Earnings from unconsolidated investments in the Condensed Consolidated Statement of Operations. The Citrus Parties also entered into a settlement on January 29, 2007 with Enron Corp. pursuant to which CCE Holdings’ obligation to remit to Enron Corp. certain proceeds of the Duke settlement was reduced, resulting in a $6.6 million gain recorded in Earnings from unconsolidated investments in the Condensed Consolidated Statement of Operations.

Citrus ENA Receivable. Citrus has previously filed bankruptcy related claims against an Enron-affiliated bankrupt company (ENA). The parties have reached a settlement in the amount of $22.7 million on the allowed claim, which was approved by the bankruptcy court in March 2007. Citrus fully reserved for the amounts in 2001 and is currently planning to evaluate offers from third parties to buy the claims.

Litigation.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Florida Gas, for damages for 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 14 - Commitments and Contingencies - Litigation.

8. Stockholders’ Equity

Dividends. On April 13, 2007, the Company paid its regular quarterly cash dividend of $0.10 per share on the Company’s common stock. Dividend payments totaling $12 million were paid to holders of record as of March 30, 2007.

9. Derivative Instruments and Hedging Activities

Interest Rate Swaps. Interest rate swaps are used to reduce interest rate risks and to manage interest expense. By entering into these agreements, the Company converts floating-rate debt into fixed-rate debt, or alternatively converts fixed-rate debt into floating-rate debt. Interest differentials paid or received under the swap agreements are reflected as an adjustment to interest expense. These interest rate swaps are financial derivative instruments that qualify for hedge treatment. The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250 million to manage its exposure against changes in future interest payments attributable to changes in the benchmark interest rate prior to the anticipated issuance of fixed-rate debt. These treasury rate locks expired on June 30, 2003, resulting in a $6.9 million after-tax loss that was recorded in Accumulated other comprehensive income (loss) and is being amortized into interest expense over the lives of the associated debt instruments. As of March 31, 2007, approximately $967,000 of net after-tax losses in Accumulated other comprehensive income (loss) will be amortized into interest expense during the next twelve months.

On April 29, 2005, the Company refinanced the existing bank loans of Trunkline LNG Holdings, LLC (LNG Holdings) in the amount of $255.6 million, due 2007. Interest rate swaps previously designated as cash flow hedges of the LNG Holdings’ bank loans were terminated upon refinancing of the loans. As a result, a gain of $3.5 million ($2.1 million, net of tax) was recorded in Accumulated other comprehensive income (loss) during the second quarter of 2005 and was amortized to interest expense through January 2007.

In March 2004, Panhandle entered into interest rate swaps to hedge the risk associated with the fair value of its $200 million principal amount of 2.75% Senior Notes. These swaps terminated in March 2007 upon their maturity. See related information in Note 10 - Debt Obligations.

13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Gathering and Processing Segment

The Company markets natural gas and natural gas liquids in its Gathering and Processing segment and manages associated commodity price risks using derivative financial instruments. These instruments involve not only the risk of dealing with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations. Under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (Statement No. 133), the Company is required to record 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.

Non-Hedging Derivatives. The Company uses various derivative financial instruments to manage commodity price risk and to take advantage of pricing anomalies among derivative financial instruments related to natural gas and natural gas liquids. The Company uses a combination of crude oil put options, fixed-price physical forward contracts, exchange-traded futures and other options, and fixed for 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. For the three-month period ended March 31, 2007, the Company recorded a pre-tax loss of $1.5 million for its non-hedging activities, $1.1 million of which is related to the crude oil put options. In March 2006, the Company recorded a pre-tax gain of $210,000 for its non-hedging activities.

Cash Flow Hedges.

The Company purchased natural gas put options to reduce the downside commodity price risk of the Southern Union Gas Services business. Prior to the closing of the Company’s acquisition of Sid Richardson Energy Services on March 1, 2006, the put options were required to be accounted for using mark-to-market accounting, which resulted in a $37.2 million pre-tax gain in the first quarter of 2006. After the closing of the acquisition, the Company designated the put options as cash flow hedges, which are accounted for in accordance with Statement No. 133. The Company purchased additional put options in July 2006 for its propane and ethane equivalent products, which were also designated as cash flow hedges. Accordingly, changes in fair value of the put options that are considered effective are initially recorded in Accumulated other comprehensive income (loss) and reclassified to earnings in the period the hedged sales occur. If it is determined that the hedge is ineffective, income is adjusted to the extent of such ineffectiveness.

Financial Statement Impact of Cash Flow Hedges.

The following table summarizes the financial statement impact of the cash flow hedges.

	Three Months Ended March 31,
	2007			2006
		(In thousands)
Change in fair value of commodity hedges - increase
(decrease) Accumulated other comprehensive income (loss),
net of tax of $(2,868) and $(3,329), respectively	$	(4,727	)	$	(5,599	)
Reclassification of unrealized gain (loss) on commodity
hedges - increase (decrease) of Operating revenues, excluding
tax of $1,287 and $0, respectively		3,409			-
Gain (loss) realized upon cash settlement - increase (decrease)
of Operating revenues		(786	)		-
Gain (loss) on ineffectiveness of commodity hedge		-			1,205
Cash realized on settlement of commodity hedges		9,366			6,683

14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

At March 31, 2007 and December 31, 2006, the Company reported in the Condensed Consolidated Balance Sheet in Prepayments and other assets, derivative asset balances of $20.4 million and $38.1 million, respectively. During 2007, the Company expects that all of the $2.5 million ($1.6 million, net of tax) loss included in the Accumulated other comprehensive income (loss) balance at March 31, 2007 will be reclassified into earnings.

Distribution Segment

Non-Hedging Activities. During 2006, the Company entered into natural gas commodity swaps and collars 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, 2007 and December 31, 2006, the fair values of the contracts, which expire at various times through March 2008, are included in the Condensed Consolidated Balance Sheet as assets and liabilities, with matching adjustments to deferred cost of gas of $1 million and $19 million, respectively.

15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

10. 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,
	2007			2006
		(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		19,500		19,500
to 2027
4.375% Senior Notes due 2008		100,000		100,000
6.15% Senior Notes due 2008		125,000		125,000
Junior Subordinated Notes due 2066		600,000		600,000
		1,504,265		1,504,265
Panhandle
2.75% Senior Notes due 2007		-		200,000
4.80% Senior Notes due 2008		300,000		300,000
6.05% Senior Notes due 2013		250,000		250,000
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 Loan due 2007		-		255,626
Term Loan due 2008		458,336		465,000
Term Loan due 2012		455,000		-
Net premiums on long-term debt		8,947		9,613
		1,639,711		1,647,667
Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt:
Credit Facilities		95,000		100,000
Total consolidated debt obligations		3,238,976		3,251,932
Less fair value swaps of Panhandle		-		1,265
Less current portion of long-term debt (1)		111,806		461,011
Less short-term debt		95,000		100,000
Total consolidated long-term debt obligations	$	3,032,170	$	2,689,656

______________________

(1)   Includes nil and $1.3 million of fair value of swaps related to debt classified as current at March 31, 2007 and December 31, 2006, respectively.

16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Long-Term Debt Obligations.

Southern Union has $3.14 billion of long-term debt recorded at March 31, 2007, of which $111.8 million is current. Debt of $2.23 billion, including net premiums of $8.9 million, is at fixed rates ranging from 4.38 percent to 9.44 percent. Southern Union also has floating rate debt, including notes payable, totaling $1.01 billion bearing an average interest rate of 6.17 percent as of March 31, 2007. The variable rate bank loans are unsecured.

As of March 31, 2007, the Company has scheduled debt payments as follows:

		Remainder										2012 and
		2007		2008		2009		2010		2011		thereafter
						(In thousands)
Southern Union	$	-	$	225,000	$	-	$	-	$	-	$	1,279,265
Panhandle		11,806		746,530		60,623		40,500		-		771,305
Total	$	11,806	$	971,530	$	60,623	$	40,500	$	-	$	2,050,570

Each note, debenture or bond is an obligation of Southern Union or a unit of Panhandle, as noted above. Panhandle’s debt is non-recourse to Southern Union. All debts that are listed as debt of Southern Union are direct obligations of Southern Union, and no debt is cross-collateralized.

On March 13, 2007, LNG Holdings, as borrower, and PEPL and Trunkline LNG Company, LLC (Trunkline LNG), as guarantors, entered into a $455 million unsecured term loan facility due March 13, 2012 (2012 Term Loan).  The interest rate under the 2012 Term Loan is a floating rate tied to a LIBOR rate or prime rate at the Company’s option, in addition to a margin tied to the rating of PEPL’s unsecured senior funded debt.  At March 31, 2007, the interest rate was 5.98 percent, including a credit spread of 62.5 basis points over LIBOR.  The proceeds of the 2012 Term Loan were used to repay approximately $455 million in existing indebtedness that matured in March 2007, including the $200 million 2.75% Senior Notes and the LNG Holdings $255.6 million Term Loan.

Short-Term Debt Obligations, Excluding Current Portion of Long-Term Debt.

Credit Facilities. Balances of $95 million and $100 million were outstanding under the Company’s credit facilities at effective interest rates of 6.5 percent and 6.02 percent at March 31, 2007 and December 31, 2006, respectively. As of May 4, 2007, there was a balance of $129 million outstanding under the Company’s credit facilities, with an effective interest rate of 6.15 percent.

Retirement of Debt Obligations

The Company plans to refinance or retire its $971.5 million of debt maturing in 2008 with proceeds from one or a combination of (i) new public debt or equity offering(s); (ii) bank financings; (iii) operating activities; and (iv) existing credit facilities. The Company is in the preliminary stages of planning for the refinancing of debt coming due in 2008. While an inability to repay these obligations would cause a material adverse change to the Company’s financial condition, the Company reasonably believes that it has the ability to refinance these obligations within the required timeframes, although there can be no assurances that the anticipated refinancings will occur.

17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11. Employee Benefits

Components of Net Periodic Benefit Cost.Net periodic benefit cost for the three-month periods ended March 31, 2007 and 2006 includes the components noted in the table below. The table excludes the net periodic benefit cost of the Company’s discontinued operations applicable to 2006. Net periodic pension cost for discontinued operations totaled $5 million for the three-month period ended March 31, 2006. Net periodic other postretirement benefit costs for discontinued operations totaled $603,000 for the three-month period ended March 31, 2006. See Note 16 - Discontinued Operations for additional related 2006 information.

		Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
		2007			2006			2007			2006
					(In thousands)
Service cost	$	664		$	694		$	489		$	604
Interest cost		2,287			2,250			1,047			1,080
Expected return on plan assets		(2,382	)		(2,204	)		(719	)		(549	)
Prior service cost amortization		127			147			(732	)		(765	)
Recognized actuarial (gain) loss		1,994			1,813			(204	)		(39	)
Sub-total		2,690			2,700			(119	)		331
Regulatory adjustment		(2,116	)		(1,983	)		666			666
Net periodic benefit cost	$	574		$	717		$	547		$	997

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 No. 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.

12. Taxes on Income

The Company's estimated annual consolidated federal and state effective income tax rate (EITR) from continuing operations for the three-month periods ended March 31, 2007 and 2006 was 28 percent and 33 percent, respectively. The decrease in the EITR from continuing operations for the 2007 period was primarily due to the tax benefit associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2007 and 2006, the tax benefit of the dividends received deduction was $10.7 million and $3.5 million, respectively.

In June 2006, the FASB issued FIN 48. The Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109. FIN 48 prescribes a recognition and measurement threshold attributable for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.

The Company adopted FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, there was no material impact on the consolidated financial statements and no adjustment to retained earnings. The amount of unrecognized tax benefits at January 1, 2007 was $600,000, all of which would impact the Company’s EITR if recognized. There are no material changes to the Company’s unrecognized tax benefits during the quarter ended March 31, 2007.

18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Company’s policy is to classify and accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense in its Condensed Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. At January 1, 2007, the Company had a liability of $2.4 million ($1.5 million, net of tax) representing interest payable to the Internal Revenue Service (IRS), state and local jurisdictions related to the completion in November 2006 of the IRS examination for the year ended June 30, 2003. There were no penalties assessed as a result of this examination. The Company paid the applicable interest to the IRS in April 2007 and anticipates the state and local interest will also be paid in 2007. There are no material changes to the amount of interest payable during the quarter ended March 31, 2007.

The Company is no longer subject to U.S. federal, state or local examinations for the tax year ended June 30, 2002 and prior years. Although the Company has settled the IRS examination of the year ended June 30, 2003, the statute remains open with the IRS until December 31, 2007. 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.

13. Regulation and Rates

Panhandle. The Company has commenced construction of an additional enhancement at its Trunkline LNG terminal. This infrastructure enhancement project, which is expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs. The project is scheduled to be in operation in 2008. In addition, Trunkline LNG and BG LNG Services agreed to extend the existing terminal and pipeline services agreements through 2028, representing a five-year extension. Approximately $59.3 million and $40.8 million of costs are included in the line item Construction work-in-progress at March 31, 2007 and December 31, 2006, respectively.

The Company has received approval from FERC to modernize and replace various compression facilities on PEPL. Such replacements will be made at twelve different compressor stations and are expected to be installed by the end of 2009. The estimated cost of these replacements is approximately $290 million, which includes the compression component of a PEPL east end project already under construction. The Company has also filed for FERC approval to replace approximately 32 miles of existing pipeline on the east end of the PEPL system with a current estimated cost of approximately $80 million, which would further improve system integrity. The project is planned to be completed in late 2007. Approximately $36.7 million and $57.9 million of costs related to these projects are included in the line item Construction work-in-progress at March 31, 2007 and December 31, 2006, respectively.

Trunkline Gas Company, LLC (Trunkline) has announced a field zone expansion project, which includes adding capacity to its pipeline system in Texas and Louisiana to increase deliveries to Henry Hub. The field zone expansion project includes the previously announced north Texas expansion as well as additional capacity to Henry Hub. Trunkline will increase the capacity along existing rights of way from Kountze, Texas, to Longville, Louisiana, by approximately 510 million cubic feet per day with the construction of approximately 45 miles of 36-inch diameter pipeline. The project includes horsepower additions and modifications at existing compressor stations. Trunkline also will create additional capacity to Henry Hub with the construction of a 13.5-mile, 36-inch diameter pipeline loop from Kaplan, Louisiana, directly into Henry Hub. The Henry Hub lateral will provide capacity of 475 million cubic feet per day from Kaplan, Louisiana to Henry Hub. Trunkline received FERC approval on April 23, 2007. This project has an anticipated in-service date during the fourth quarter of 2007. The Company estimates the project will cost approximately $200 million plus capitalized interest, including a $40 million contribution in aid of construction (CIAC) to a subsidiary of Energy Transfer Partners, L.P. (Energy Transfer) to move its delivery point to a location near Buna, Texas, increasing the field zone project capacity by up to 330,000 dekatherms per day. Energy Transfer has recently indicated that the Buna route is problematic and the parties are currently engaged in discussion of alternate delivery points. The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer, additional capacity created, and sale by Trunkline of the additional capacity. Approximately $17.2 million and $12.5 million of costs for this project are included in the line item Construction work-in-progress at March 31, 2007 and December 31, 2006, respectively.

19

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

FERC is responsible under the Natural Gas Act for assuring that rates charged by interstate pipelines are "just and reasonable."  To enforce that requirement, FERC applies a ratemaking methodology that determines an allowed rate of return on common equity for the companies it regulates.  On October 25, 2006, a group including producers and various trade associations filed a complaint under Section 5 of the Natural Gas Act against Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage) requesting that FERC initiate an investigation into Southwest Gas Storage’s rates, terms and conditions of service and grant immediate interim rate relief. FERC initiated a Section 5 proceeding on December 21, 2006, setting this issue for hearing. Pursuant to FERC order, Southwest Gas Storage filed a cost and revenue study with FERC on February 20, 2007, with a hearing scheduled for August 27, 2007. The ultimate resolution of the Southwest Gas Storage matter has many variables and potential outcomes and it is impossible to predict its timing or materiality at this time.  No proceeding has been initiated against PEPL, but any potential rate reductions from such a proceeding would be expected to be mitigated by the impact of significant ongoing capital spending at PEPL for pipeline integrity, safety, environmental (including air emissions), compression modernization and other requirements.

On January 26, 2007, Southwest Gas Storage filed an abandonment application to reduce the certificated storage capacity of its North Hopeton field by approximately 6 Bcf.  This filing brings the certificated capacity in line with operational performance of the field.  Southwest Gas Storage has entered into a third party agreement to replace this storage capability.

On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as HCAs. This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The rule requires operators to have identified HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing or direct assessment, by June 2004. Operators must rank the risk of their pipeline segments containing HCAs and must complete assessments on at least 50 percent of the segments using one or more of these methods by December 2007. Assessments will generally be conducted on the higher risk segments first, with the balance being completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the in-line inspections. All systems operated by the Company will be compliant with the rule; however, while identification and location of all HCAs has been completed, it is not practicable to determine the total scope of required remediation activities prior to completion of the assessments and inspections. The required modifications and inspections for Panhandle are preliminarily estimated to be in the range of approximately $22.5 million to $30 million per year through 2009, inclusive of remediation costs.

Missouri Gas Energy. On May 1, 2006, Missouri Gas Energy announced the filing of a proposal with the Missouri Public Service Commission (MPSC) to increase annual revenues by approximately $41.7 million, or 6.8 percent. The MPSC issued its Report and Order on March 22, 2007, authorizing an annual revenue increase of $27.2 million, or 4.5 percent. In its order, the MPSC calculated the revenue increase using a return on equity of 10.5 percent and set residential rates using a straight fixed-variable rate design, thereby eliminating the impact of weather and conservation on residential margin revenues and related earnings. The new rates went into effect on April 3, 2007.

Through filings made on various dates, the staff of the MPSC has recommended that the MPSC disallow a total of approximately $47.7 million in gas costs incurred during the period July 1, 1997 through June 30, 2005. Missouri Gas Energy disputes the basis of $35.3 million of the total proposed disallowance, which appears to be the same as was rejected by the MPSC through an order dated March 12, 2002, applicable to the period July 1, 1996 through June 30, 1997. No date for a hearing in this matter has been set and it appears unlikely, based upon a ruling of the Missouri Supreme Court issued on January 30, 2007, that the $35.3 million disallowance will be pursued by the MPSC. Missouri Gas Energy also disputes the basis of $3.9 million of the total proposed disallowance, applicable to the period July 1, 2000 through June 30, 2001, which was the subject of a hearing concluded in November 2003, and is presently awaiting decision by the MPSC. In addition, Missouri Gas Energy disputes the basis of $4.1 million of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003; a hearing was held in August 2006 and Missouri Gas Energy is presently awaiting a decision by the MPSC. Finally, Missouri Gas Energy disputes the basis of $4.4 million of the proposed

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

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disallowance for the period of July 1, 2004 through June 30, 2005 (which appears to be the same as or very similar to the basis of the disallowance considered at the August 2006 hearing); this matter has not yet been set for hearing. 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.

New England Gas Company. On June 15, 2006, New England Gas Company filed a notice of intent to file rate schedules for its Massachusetts operations with the Massachusetts Department of Telecommunications and Energy (MDTE). Such notice is a requirement in advance of filing for an increase in base gas rates. The Company has been engaged in settlement discussions with the Massachusetts Attorney General’s office regarding a rate increase and hopes to file a settlement with the MDTE in the second quarter of 2007.

14. 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, 2007 and December 31, 2006 to cover probable environmental response actions:

	March 31,			December 31,
		2007		2006
		(In thousands)
Current	$	5,495	$	5,098
Noncurrent		18,766		18,632
Total Environmental Liabilities	$	24,261	$	23,730

Transportation and Storage Segment Environmental Matters.

Gas Transmission Systems.Panhandle is responsible for environmental remediation at certain sites on its gas transmission systems. The contamination resulted 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

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(UNAUDITED)

that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline system, PCBs were recently 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 assessment program is being developed to determine whether this condition exists at any of the other 78 similar buildings on the PEPL and Trunkline systems. Until the results of the assessment program are available, 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, have been 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. PEPL and Trunkline received notices of potential liability from the U.S. EPA for the Dunavan site by letters dated September 30, 2005. The notices demanded reimbursement to the U.S. EPA for costs incurred to date in the amount of approximately $1.8 million and encouraged each PRP to voluntarily negotiate an administrative settlement agreement with the U.S. EPA within certain limited time frames providing for the PRPs to conduct or finance the response activities required at the site.  The demand was declined in a joint letter dated December 15, 2005 by the major PRPs, including PEPL and Trunkline. 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 release occurred in the form of a mist at a valve that was in use to reduce the pressure in the pipeline as part of maintenance activities. The hydrocarbon mist affected several acres of adjacent agricultural land and a nearby marina. Approximately 27 gallons of hydrocarbons reached the Mississippi River. PEPL contacted appropriate federal and state regulatory agencies and 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. On December 14, 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. By letter dated November 22, 2006, PEPL received a follow-up information request from the IEPA on the status of certain measures PEPL had agreed to undertake in connection with the original responses to the violation notice. 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 July 10, 2006, PEPL identified the possible subsurface release of approximately 745 gallons of methanol from a tank located at the Howell compressor station. Subsequent testing of the tank and associated piping confirmed that a release had taken place. Impacted soils were excavated in accordance with state specific regulatory requirements. The impacted soils were transported to an authorized disposal facility. The appropriate federal and state environmental agencies were notified of this release. The Michigan Department of

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Environmental Quality (MDEQ) conducted an inspection of the remediation effort on October 17, 2006 and indicated that an appropriate response and remediation action had been implemented. A final remediation report was submitted to the MDEQ and U.S. EPA on January 25, 2007. 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. The U.S. EPA issued a final rule on regional ozone control (NOx SIP Call) in April 2004 that impacts Panhandle in two midwestern states, Indiana and Illinois. Based on a U.S. EPA guidance document negotiated with gas industry representatives in 2002, Panhandle is required in states that follow the U.S. EPA guidance to reduce nitrogen oxide (NOx) emissions by 82 percent on the identified large internal combustion engines and will be able to trade off engines within Panhandle in an effort to create a cost effective NOx reduction solution. The final implementation date is May 2007. The rule will affect 20 large internal combustion engines on Panhandle’s system in Illinois and Indiana with an approximate cost of $22.3 million for capital improvements through 2007, based on current projections. Approximately $21.7 million of the $22.3 million of capital expenditures have been incurred as of March 31, 2007. Indiana has promulgated state regulations to address the requirements of the NOx SIP Call rule that essentially follow the U.S. EPA guidance.

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.  The proposed Illinois rule requires controls on engines regulated under the U.S. EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2011.  The state is requiring the controls to comply with U.S. EPA rules regarding the NOx SIP Call, ozone non-attainment and fine particulate standards. However, the statewide applicability provision proposed by the IEPA reaches beyond federal requirements without apparent justification. A pipeline consortium including PEPL and Trunkline filed an objection to the rule on April 16, 2007 requesting the IPCB to bifurcate and address separately the statewide applicability provision. The pipeline consortium specifically objected to treatment of the statewide applicability issue under an Illinois “Fast Track” rulemaking process. The Fast Track rulemaking process was developed and premised on meeting federally driven requirements.  In an order dated April 19, 2007, the IPCB set in motion a schedule of hearings based on the Fast Track process pending the IPCB’s ruling on the objections.  The IEPA filed a response to the objections on May 1, 2007.  The first hearing is scheduled to start on May 21, 2007. The statewide applicability portion of the proposed Illinois rule serves as the primary driver of costs for PEPL and Trunkline. As currently proposed, the rule applies to all PEPL and Trunkline stations in Illinois. Preliminary estimates indicate compliance with the proposed rule would require minimum capital expenditures of approximately $45 million for emission controls in addition to the $22.3 million associated with federally based NOx reductions described above. 

In 2002, the Texas Commission on Environmental Quality (TCEQ) enacted the Houston/Galveston SIP regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and requires the installation of emission controls. New regulations also require certain grandfathered facilities in East Texas to enter into the new source permit program which may require the installation of emission controls at one additional facility owned by Panhandle. Management estimates capital improvements of $17.6 million will be needed at the two affected Texas locations. Approximately $16.4 million of the $17.6 million of capital expenditures have been incurred as of March 31, 2007. Permit limits were placed on grandfathered engines at two facilities in West Texas that are owned by PEPL. An estimated $3 million in capital expenditures will be required to comply with permit limitations.

The U.S. EPA promulgated various Maximum Achievable Control Technology (MACT) rules in February 2004. The rules require that PEPL and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources. Most PEPL and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for PEPL and Trunkline is formaldehyde. As promulgated, the rule seeks to reduce formaldehyde emissions by 76 percent from these engines. Catalytic controls will be required to reduce emissions under these rules with a final implementation date of June 2007. PEPL and Trunkline could have up to 20 internal combustion engines subject to the rules. Management expects that compliance with these regulations will necessitate an estimated expenditure of $1.1 million for capital improvements, based on current projections. Most of the expenditures are required to lower facility emissions below thresholds of the EPA MACT applicability.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Spill Control. Environmental regulations were recently modified for the U.S. EPA’s SPCC program. The Company is currently reviewing the impact of the modified regulations on its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions 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.

Gathering and Processing Segment Environmental Matters.

Gathering and Processing Systems.Southern Union Gas Services is responsible for environmental remediation at certain sites on its gathering and processing systems. The contamination results 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, Southern Union Gas Services 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. As the facility operator with a 50 percent interest in the site, Southern Union Gas Services is currently in negotiations with the TCEQ to finalize permit requirements for the Grey Ranch facility. Although Southern Union Gas Services is requesting that no control measures be required at this time, there can be no assurance such control measures will not be required. Costs associated with emission controls, if any, cannot be estimated with certainty prior to issuance of the final permit, but the Company believes such costs will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Spill Control. Environmental regulations were recently modified for the U.S. EPA’s SPCC program. Southern Union Gas Services is currently reviewing the impact of the modified regulations on its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions 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.

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 from 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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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 is working with MADEP to obtain access to a number of these off-site properties to complete the investigation. The most recent reports filed with MADEP in September 2006 propose a remedy for the upland portion of the site by means of an engineered barrier, construction of which is anticipated in 2008. Completion of the investigation and any necessary future remediation are contingent upon obtaining access to the off-site properties. It is estimated that the Company will spend approximately $8.8 million 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. The Case Management Order in that proceeding calls for the completion of discovery by November 15, 2007. 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.

During 2005, four lawsuits were filed against New England Gas Company in Rhode Island regarding the Tiverton neighborhood. 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. The Court entered a scheduling order setting a deadline for completion of discovery by November 15, 2007. The Company will continue to vigorously defend itself against all four lawsuits. Parts of the Tiverton neighborhood appear to have been built on fill placed there at various times and include one or more historic waste disposal sites. Research is therefore underway by the Company to identify other PRPs associated with the fill materials and the waste disposal. Under the terms of the Purchase and Sale Agreement between the Company and National Grid USA for the sale of the Rhode Island operations of the Company’s New England Gas Company natural gas distribution business, the potential obligation for the matters described above remains with the Company. 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.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Mercury Release. On October 19, 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. State and federal authorities continue to investigate the incident. The Company is discussing with the authorities New England Gas Company’s compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and communication requirements. The Company received and complied with a subpoena requesting documents relating to this matter. In January and March 2007, the Company received additional document subpoenas in this matter. The Company is aware that the government continues to present evidence to a grand jury on this matter. The U.S. Attorney’s office in Rhode Island has advised the Company that this incident may give rise to unspecified criminal charges against the Company. While the Company believes any such charges would be unfounded, the Company now expects that criminal charges will be brought against the Company. The Company would vigorously defend any such action.

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. In addition, an attorney for unspecified residents of the neighboring apartment complex who are not associated with the filed litigation has made a demand upon New England Gas Company. Under the terms of the Purchase and Sale Agreement between the Company and National Grid USA, the potential obligation for the matters described above remains with the Company. 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.

Hope Land. Hope Land Mineral Corporation (Hope Land) contends that it owns the storage rights to property that contains a portion of the Company’s Howell storage field. During June 2003, the Michigan Court of Appeals reversed the trial court’s previous order, which had granted summary judgment in favor of the Company and dismissed the case. The Company filed an appeal of the Court of Appeals order with the Michigan Supreme Court, which was denied in December of 2003. In April 2005, Hope Land filed trespass and unjust enrichment complaints against the Company to prevent running of the statute of limitations. The Company then filed an action for condemnation to obtain the storage rights from Hope Land. Pursuant to a pre-filing settlement with Hope Land, the Company obtained legal title to the storage rights upon the filing of the condemnation action. The unjust enrichment claims were dismissed and then reinstated on December 6, 2006. The trial commenced in April 2007, and on May 2, 2007, the jury awarded Hope Land total compensation of approximately $91,000 in respect of condemnation and trespass.

Jack Grynberg. Jack Grynberg, an individual, has filed actions against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, for damages for 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. 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.

Southwest Gas Litigation. During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire Southwest Gas Corporation (Southwest). All of these actions eventually

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

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(UNAUDITED)

were transferred to the U.S. District Court for the District of Arizona (District Court). The trial of the Company’s claims against the sole remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to the Company of nearly $400,000 in actual damages and $60 million in punitive damages against former Commissioner Irvin. On July 25, 2005, the Ninth Circuit Court of Appeals (Ninth Circuit) denied former Commissioner Irvin’s motions to set aside the verdict and affirmed the judgment against former Commissioner Irvin for compensatory damages and determined that punitive damages were appropriate but found that the $60 million punitive damage award against former Commissioner Irvin was excessive. Accordingly, the Ninth Circuit remanded that issue to the District Court for further action. The District Court reconsidered the punitive damages award and entered an order of remittitur on November 21, 2006, reducing the punitive damages amount to $4 million, plus interest. Irvin has filed another notice of appeal. The Company intends to continue to vigorously pursue its case against former Commissioner Irvin, including seeking to collect all damages ultimately determined to lie against him. There can be no assurance, however, as to the amount of such damages, or as to the amount, if any, that the Company ultimately will collect.

Mineral Management Service. In 1993, the U.S. Department of the Interior announced its intention to seek, through its Mineral Management Service (MMS), additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements and buyouts and buydowns of gas sales contracts with natural gas pipelines. PEPL and Trunkline, with respect to certain producer contract settlements, may be contractually required to reimburse or, in some instances, to indemnify producers against such royalty claims. The potential liability of the producers to the government and of the pipelines to the producers involves complex issues of law and fact, which are likely to take substantial time to resolve. If required to reimburse or indemnify the producers, PEPL and Trunkline may file with FERC to recover these costs from pipeline customers. The Company believes these commitments and contingencies will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Other Commitments and Contingencies.

Hurricane-Related Expenditures. Late in the third quarter of 2005, after coming through the Gulf of Mexico, 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. As of March 31, 2007, the Company has incurred approximately $32 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 Hurricane Rita in excess of its $5 million deductible. Such reimbursement is currently estimated by the Company’s property insurance carrier ultimately to be limited to 70 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. An estimated $10 million of the costs incurred related to the Trunkline LNG terminal expansion are not eligible for insurance recovery. As of March 31, 2007, the Company has received payments of $1.6 million from its insurance carriers. No receivables due from the insurance carriers have been recorded as of March 31, 2007.

In addition, after the 2005 hurricanes, the MMS mandated inspections by leaseholders and pipeline operators along the hurricane tracks. The Company has detected exposed pipe and other facilities on Trunkline and Sea Robin that must be re-covered to comply with applicable regulations. Capital expenditures are estimated at $4.8 million, $1.2 million of which had been incurred as of March 31, 2007. The Company will seek recovery of these expense and capital amounts as part of the hurricane-related claims.

Energy Transfer Commitment. In November 2006, PEPL provided a guaranty to a subsidiary of Energy Transfer, a non-affiliate, for the full performance by Trunkline of a $40 million CIAC obligation related to a modification of a field zone expansion project expected to be completed in late 2007. The CIAC would be made by Trunkline upon movement of Energy Transfer’s delivery point to a location originally anticipated to be near Buna, Texas. Energy Transfer has recently indicated that the Buna route is problematic and the parties are currently engaged in discussion of alternate delivery points. The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer, additional capacity created, and

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

sale by Trunkline of the additional capacity.

15. Reportable Segments

The Company’s operating segments are aggregated into reportable business segments 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.

The Transportation and Storage segment operations are conducted through Panhandle and the 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.

Southern Union Gas Services, which comprises the Gathering and Processing segment, is primarily engaged in the gathering, transmission, 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. The Company’s discontinued operations related to its former PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division. During the first quarter of 2006, the Company entered into definitive agreements to sell the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division. The Company completed the sales in August 2006. See Note 16 - Discontinued Operations.

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 from continuing operations, 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 operating cash flow.

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, 2007 and 2006.

The following table sets forth certain selected financial information for the Company’s segments for the three-month periods ended March 31, 2007 and 2006. Financial information for the Gathering and Processing segment reflects operations of Southern Union Gas Services beginning on its acquisition date of March 1, 2006.

28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Three Months Ended March 31,
Segment Data		2007			2006
		(In thousands)
Revenues from external customers:
Transportation and Storage	$	169,030		$	144,643
Gathering and Processing		296,055			103,231
Distribution		314,257			298,229
Total segment operating revenues		779,342			546,103
Corporate and other		890			1,063
	$	780,232		$	547,166
Depreciation and amortization:
Transportation and Storage	$	20,709		$	17,474
Gathering and Processing		14,587			5,552
Distribution		7,618			7,583
Total segment depreciation and amortization		42,914			30,609
Corporate and other		550			256
	$	43,464		$	30,865
Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	30,384		$	11,564
Gathering and Processing		526			-
Corporate and other		(14	)		2
	$	30,896		$	11,566
Other income (expense), net:
Transportation and Storage	$	588		$	1,772
Gathering and Processing		(875	)		409
Distribution		(395	)		(1,208	)
Total segment other income (expense), net		(682	)		973
Corporate and other		969			36,120
	$	287		$	37,093
Segment performance:
Transportation and Storage EBIT	$	115,218		$	86,801
Gathering and Processing EBIT		8,882			7,113
Distribution EBIT		33,545			29,989
Total segment EBIT		157,645			123,903
Corporate and other		3,132			27,603
Interest expense		52,185			42,221
Federal and state income tax expense		29,871			35,867
Net earnings from continuing operations		78,721			73,418
Earnings from discontinued operations before
income taxes		-			38,009
Federal and state income tax expense		-			13,480
Net earnings from discontinued operations		-			24,529
Net earnings		78,721			97,947
Preferred stock dividends		4,341			4,341
Net earnings available for common stockholders	$	74,380		$	93,606

29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	March 31,			December 31,
Segment Data		2007		2006
		(In thousands)
Total assets:
Transportation and Storage	$	3,967,715	$	3,874,318
Gathering and Processing		1,675,197		1,722,055
Distribution		958,867		1,016,491
Total segment assets		6,601,779		6,612,864
Corporate and other		157,465		169,926
Total consolidated assets	$	6,759,244	$	6,782,790
		Three Months Ended March 31,
		2007		2006
		(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	46,808	$	28,819
Gathering and Processing		12,356		2,496
Distribution		7,114		9,322
Total segment expenditures for
long-lived assets		66,278		40,637
Corporate and other		634		672
Total consolidated expenditures for
long-lived assets	$	66,912	$	41,309

16. Discontinued Operations

On August 24, 2006, the Company completed the sale of the assets of its PG Energy natural gas distribution division to UGI Corporation for $580 million in cash, excluding certain working capital adjustment reductions of approximately $24.4 million. Additionally, on August 24, 2006, the Company completed the sale of the Rhode Island operations of its New England Gas Company natural gas distribution division to National Grid USA for $575 million in cash, less the assumption of approximately $77 million of debt and excluding certain working capital adjustment reductions of approximately $24.9 million.

The results of operations of these divisions have been segregated and reported as Discontinued operations in the Condensed Consolidated Statement of Operations for all periods presented. The PG Energy natural gas distribution division and Rhode Island operations of the New England Gas Company natural gas distribution division were historically reported within the Distribution segment.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table summarizes the combined results of operations that have been segregated and reported as discontinued operations in the Condensed Consolidated Statement of Operations.

	Three Months Ended
	March 31, 2006
	(In thousands,except per share amounts)
Operating revenues	$	348,765
Operating income		44,781
Net earnings from discontinued operations (1)		24,529
Net earnings available from discontinued operations per share:
Basic	$	0.22
Diluted	$	0.22

__________________

(1)  Net earnings from discontinued operations do not include any allocation of corporate interest expense or other corporate costs.

17. Acquisition Pro Forma Financial Information

The following unaudited pro forma financial information for the period presented is reported as though the acquisition of Sid Richardson Energy Services and the related permanent financing, including utilization of the proceeds from the August 2006 sales of the Company’s Pennsylvania and Rhode Island natural gas distribution divisions, occurred on January 1, 2006. The pro forma financial information is not necessarily indicative of the results that would have been obtained if the acquisition of Sid Richardson Energy Services and the related financing had been completed as of the assumed date for the period presented or of the results that may be obtained in the future.

	Three Months Ended
	March 31, 2006
	(In thousands,except per share amounts)
Operating revenue	$	777,715
Net earnings available for common shareholders
from continuing operations		66,189
Net earnings available for common shareholders from continuing
operations per share:
Basic	$	0.59
Diluted	$	0.58

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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 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.

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 from continuing operations, 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 operating cash flow.

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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,
	2007		2006
	(In thousands)
EBIT:
Transportation and storage segment	$	115,218	$	86,801
Gathering and processing segment		8,882		7,113
Distribution segment		33,545		29,989
Corporate and other		3,132		27,603
Total EBIT		160,777		151,506
Interest		52,185		42,221
Earnings from continuing operations before
income taxes		108,592		109,285
Federal and state income taxes		29,871		35,867
Net earnings from continuing operations		78,721		73,418
Discontinued operations:
Earnings from discontinued operations
before income taxes		-		38,009
Federal and state income taxes		-		13,480
Net earnings from discontinued operations		-		24,529
Preferred stock dividends		4,341		4,341
Net earnings available for common stockholders	$	74,380	$	93,606

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. The Company’s $19.2 million decrease in Net earnings available for common stockholders was primarily due to:

·   The August 2006 sales of the assets of the PG Energy natural gas distribution division and the Rhode Island operations of the New England Gas Company natural gas

    distribution division which contributed $24.5 million of Net earnings from discontinued operations in the first quarter of 2006; and

·   The pre-acquisition pre-tax mark-to-market gain of $37.2 million in the 2006 period on the put options associated with the acquisition of Sid Richardson Energy Services.

These earnings reductions were partially offset by:

·   The $28.4 million of higher EBIT contribution from the Transportation and Storage segment largely due to higher LNG terminalling revenue associated with the Trunkline LNG

        expansions completed in April and July 2006, and higher equity earnings from Citrus resulting from settlement of litigation and the Company’s increased equity ownership in Citrus

        from 25 percent to 50 percent effective December 1, 2006; and

·   A lower EITR for continuing operations of 28 percent in the first quarter of 2007 versus 33 percent for the 2006 period.

Business Segment Results

Transportation and Storage Segment. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas to the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services.Prior to the closing of the transactions on December 1, 2006 whereby Energy Transfer and CCE Holdings entered into a definitive redemption agreement resulting in the Company transferring its interest in Transwestern in exchange for Energy Transfer’s interest in CCE Holdings (Redemption Agreement), the Transportation and Storage segment also provided service to the Southwest region through its interest in Transwestern. The Transportation and Storage segment’s operations, now conducted through Panhandle and Florida Gas, are regulated as to rates and other matters by FERC. The Transportation and Storage segment’s operations are somewhat sensitive to weather and are seasonal in nature with a significant percentage of annual

33

operating revenues and EBIT occurring in the traditional winter heating season.

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. However, changes in commodity prices and volumes transported do not generally have a significant short-term impact on operating revenues because 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		2007		2006
		(In thousands)
Operating revenues	$	169,030	$	144,643
Operating expenses		56,280		46,354
Depreciation and amortization		20,709		17,474
Taxes other than on income
and revenues		7,795		7,350
Total operating income		84,246		73,465
Earnings from unconsolidated
investments		30,384		11,564
Other income, net		588		1,772
EBIT	$	115,218	$	86,801

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. The $28.4 million EBIT improvement in the three-month period ended March 31, 2007 versus the same period in 2006 was primarily due to improved contributions from Panhandle totaling $9.6 million and higher equity earnings from the Company’s investment in Citrus of $18.8 million.

Panhandle’s $9.6 million EBIT improvement was primarily related to the following items:

·   Higher operating revenues of $24.4 million primarily due to:

o   A $13.3 million increase in LNG terminalling revenue due to a capacity increase on the BG LNG Services contract as a result of the Trunkline LNG Phase I and Phase II expansions, which were placed in service in April 2006 and July 2006, respectively, as well as higher volumes resulting from an increase in LNG cargoes; and

o   Increased transportation and storage revenue of $12.4 million due to higher parking revenues of $4.7 million, higher reservation revenues of $4.3 million, which were primarily driven by higher average rates on contracts, higher storage revenues of $2.3 million due to increased contracted capacity and higher commodity revenues of $1.1 million due to higher volumes.

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·   Higher operating expenses of $9.9 million primarily due to:

·   A $3.8 million increase in corporate costs due to Southern Union’s disposition of certain assets during 2006 resulting in a larger allocation of corporate costs to the remaining business units, including Panhandle;

·   A $2.1 million increase in LNG power costs resulting from increased cargoes;

·   A $1.2 million increase in Sea Robin fuel tracker costs due to underrecovery in the first quarter of 2007;

·   A $1 million increase in labor and benefits costs;

·   A $600,000 increase in insurance expense due to higher premiums and higher workers’ compensation losses;

·   A $500,000 increase in legal costs; and

·   A $500,000 increase in contract storage costs primarily due to an increase in leased capacity and overrun charges.

·   Increased depreciation and amortization expense of $3.2 million due to an increase in property, plant and equipment placed in service in 2007, including the Trunkline LNG Phase I and Phase II expansions; and

·   A $1.2 million decrease in other income, net primarily due to a gain on sale of certain Trunkline assets in 2006.

Equity earnings were higher by $18.8 million in 2007 versus 2006 primarily due to the following items, adjusted where applicable to reflect the Company’s proportionate equity share:

·   Higher equity earnings of approximately $10.2 million from Citrus largely due to the Company’s increased effective ownership to 50 percent from 25 percent as a result of the transactions under the Redemption Agreement, which closed in December 2006.

·   A nonrecurring gain of $7.5 million recognized by Citrus associated with settlement of a lawsuit with Duke more fully described in PART I,Item 1. Financial Statements (Unaudited), Note 7 - Unconsolidated Investments - Citrus Trading Litigation; and

·   A $6.6 million gain related to a reduced liability to Enron previously established associated with the Duke lawsuit settlement referenced above.

The higher equity earnings in 2007 versus 2006 were partially offset by the $5.6 million of earnings in 2006 attributable to Transwestern. The Company’s interest in Transwestern was transferred to Energy Transfer in December 2006 in connection with the redemption of Energy Transfer’s interest in CCE Holdings pursuant to the Redemption Agreement.

Gathering and Processing Segment. The Gathering and Processing segment is primarily engaged in the gathering, transmission, treating, processing and redelivery of natural gas and natural gas liquids in Texas and New Mexico. Its operations are conducted through Southern Union Gas Services. The results of operations provided by Southern Union Gas Services have been included in the Condensed Consolidated Statement of Operations since its March 1, 2006 acquisition.

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

	Three Months			Inception
		Ended			Through
Gathering and Processing Segment		March 31, 2007			March 31, 2006 (1)
		(In thousands)
Operating revenues	$	296,055		$	103,231
Cost of gas and other energy		253,829			86,158
Operating expenses		17,668			4,817
Depreciation and amortization		14,587			5,552
Taxes other than on income and revenues		740			-
Total operating income		9,231			6,704
Earnings (loss) from unconsolidated investments		526			-
Other income, net		(875	)		409
EBIT	$	8,882		$	7,113

________________

(1) Represents results from operations for the period subsequent to the March 1, 2006 acquisition.

Three-month period ended March 31, 2007 versus the one-month period ended March 31, 2006.

Southern Union Gas Services’ EBIT for the three-month period ended March 31, 2007 and one-month period ended March 31, 2006 was $8.9 million and $7.1 million, respectively. The Company experienced an unusually high level of fuel, flare and unaccounted for gas losses of approximately $3.6 million during the first quarter of 2007, $1.1 million of which is attributable to a one-time event experienced at the Mi Vida facility. Lower average monthly gas processing spreads of approximately $0.03 to $0.04 per gallon in the 2007 versus the 2006 period resulted in a monthly average reduction of revenues by approximately $400,000 to $500,000.

In the first quarter of 2007, the Company recorded a net increase to earnings of $2.6 million related to its put option hedges versus a $1.2 million increase recorded in March 2006. Additionally, in the first quarter of 2007, the Company recorded a loss on its non-hedging activities of $1.5 million, $1.1 million of which is related to the crude oil puts. The March 2006 non-hedging activities resulted in a gain of $210,000. See Part I, Item 1. Financial Statements (Unaudited), Note 9 - Derivative Instruments and Hedging Activities - Gathering and Processing Segment for additional related information.

Operating and other expenses were higher generally due to the incurrence of three months of operations in the 2007 period versus one month in 2006. In addition, Southern Union Gas Services suffered in the first quarter of 2007 a non-recurring loss of $878,000 related to a compressor engine destroyed by fire and also recorded higher average corporate costs of approximately $600,000 per month in the 2007 period due to Southern Union’s disposition of certain assets during 2006 resulting in a larger allocation of corporate costs to the remaining business units.

Distribution Segment. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri and Massachusetts. The Company’s utilities operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. The utilities operations have historically been generally sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues and EBIT occurring in the traditional winter heating season in the first and fourth calendar quarters. However, the MPSC approved distribution rates effective April 3, 2007 for Missouri Gas Energy’s residential customers (which comprise approximately 85 percent of its total customers and approximately 65 percent of its margin revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri. See PART I, ITEM 1. Financial Statements (Unaudited), Note 13 - Regulatory and Rates - Missouri Gas Energy for additional information related to the new Missouri Gas Energy rates.

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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	2007			2006
	(In thousands)
Net operating revenues (1)	$	68,002		$	61,716
Operating expenses		23,281			20,240
Depreciation and amortization		7,618			7,583
Taxes other than on income
and revenues		3,163			2,696
Total operating income		33,940			31,197
Other income (expenses), net		(395	)		(1,208	)
EBIT	$	33,545		$	29,989

________________

(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.

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. The $3.6 million EBIT improvement in the three-month period ended March 31, 2007 versus the same period in 2006 was primarily due to the following items:

·   Net operating revenues increased $6.3 million primarily due to a 14 percent increase in consumption volumes resulting from colder weather in 2007 as evidenced by a 14 percent increase in degree days in 2007 versus 2006; and

·   Higher operating expenses of $3 million primarily due to:

o   Increased labor expenses of approximately $948,000 primarily due to higher headcounts due to the filling of vacant positions and merit increases in 2007 versus 2006;

o   Increased general expenses of approximately $1.1 million primarily due to cathodic protection maintenance and outsourcing of billing services; and

o   Higher legal costs of approximately $700,000.

Corporate and Other

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006.  The $24.5 million EBIT reduction for the three-month period ended March 31, 2007 versus the same period in 2006 was primarily due to the following items:

·Impact of a mark-to-market gain in 2006 of $37.2 million on put options for the pre-acquisition period associated with the March 1, 2006 acquisition of Sid Richardson Energy Services;

·Impact of a first quarter 2006 $6.5 million write down in the carrying value of the Scranton corporate building;

·Impact of a $1.0 million charge to record a reserve in March 2006 for final estimated costs resulting from a sales and use tax audit; and

·Lower corporate stock-based compensation costs of approximately $1.1 million in 2007 versus 2006.

Interest Expense

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. Interest expense was $10 million higher in 2007 compared with 2006 primarily due to:

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·   Interest expense of $10.8 million related to the $600 million Junior Subordinated Notes issued in October 2006;

·   Increased interest expense of $9.2 million related to Panhandle debt primarily due to higher average interest rates and higher debt balances in 2007 versus 2006;

·   Interest expense of $1.9 million under the 6.15% Senior Notes issued in August 2006;

·   Lower interest expense of $7.2 million and debt issuance cost amortization of $1.3 million in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, which was retired in October 2006; and

·   Lower interest expense of $2.1 million associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2007 compared to 2006.

Federal and State Income Taxes from Continuing Operations

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. The EITR from continuing operations for the three-month periods ended March 31, 2007 and 2006 was 28 percent and 33 percent, respectively.The decrease in the EITR from continuing operations for the 2007 period was primarily due to the tax benefit associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus. For the three-month periods ended March 31, 2007 and 2006, the tax benefit of the dividends received deduction was $10.7 million and $3.5 million, respectively.

Net Earnings from Discontinued Operations

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006.Earnings from discontinued operations before income taxes for the three-month period ended March 31, 2006 was $38 million ($24.5 million, net of tax). The Company completed its sales of the assets of its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division in August 2006. The Company’s EITR from discontinued operations was 35 percent in 2006.

Preferred Stock Dividends

There is no change in dividends on preferred securities for the three-month periods ended March 31, 2007 and 2006.

LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity. Additional sources of liquidity include use of available credit facilities, various equity offerings, project and bank financings, issuance of long-term debt and proceeds from asset dispositions. The availability and terms of any such financing sources 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 due to factors such as the Company's ability to realize any anticipated benefits from the acquisitions, successful integration of new and different operations and businesses and effects of different regional economic and weather conditions. 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.

Operating Activities

Three-month period ended March 31, 2007 versus the three-month period ended March 31, 2006. Cash flows provided by operating activities were $122.5 million for the three-month period ended March 31, 2007 compared with cash flows provided by operating activities of $144.9 million for the same period in 2006. Cash flows provided by operating activities before changes in operating assets and liabilities for 2007 were $166.2 million compared with $121.6 million for 2006. Changes in operating assets and liabilities used cash of $43.7 million in 2007 and provided

38

cash of $23.3 million in 2006, resulting in a decrease in cash of $67 million in 2007 compared to 2006. The $67 million decrease in cash is primarily due to higher usage of cash by accounts payable and deferred charges and credits. These amounts were somewhat offset by lower natural gas inventory levels resulting from higher withdrawals from storage in the 2007 period due to colder winter weather.

Investing Activities

Summary

The Company’s business strategy includes making prudent capital expenditures across its base of interstate transmission, 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, 2007 and 2006 were $68.8 million and $1.58 billion, respectively. The $1.51 billion decrease in invested cash is primarily due to the $1.54 billion (net of $53.2 million cash received) acquisition of Sid Richardson Energy Services completed on March 1, 2006. The following table presents a summary of additions to property, plant and equipment in continuing operations by segment, including additions related to major projects for the periods presented.

		Three Months Ended March 31,
Property, Plant and Equipment Additions		2007		2006
		(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	17,632	$	13,894
Trunkline LNG Field Zone Expansion		7,572		-
East End Enhancement		3,629		917
Compression Modernization		3,200		-
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance		14,775		14,008
Total		46,808		28,819
Gathering and Processing Segment		12,356		2,496	(1)
Distribution Segment
Missouri Safety Program		1,122		2,287
Other, primarily system replacement
and expansion		5,992		7,035
Total		7,114		9,322
Corporate and other		634		672
Total (2)	$	66,912	$	41,309

____________________

(1) Reflects expenditures for the period subsequent to the March 1, 2006 acquisition of Sid Richardson Energy Services versus the three-month period ended March 31, 2006.

(2) Includes net capital accruals totaling $(3.1) million and $(2.6) million for the three-month periods ended March 31, 2007 and 2006, respectively.

See PART I, ITEM 1. Financial Statements (Unaudited), Note 13 - Regulation and Rates and Note 11 - Commitments and Contingencies - Other Commitments and Contingencies, in this Quarterly Report on Form 10-Q for a discussion of the Company’s principal capital expenditure projects.

Missouri Safety Program. Pursuant to a 1989 MPSC order, Missouri Gas Energy is engaged in a major gas safety program in its service territories (Missouri Safety Program). This program includes replacement of Company and

39

customer-owned gas service and yard lines, the movement and resetting of meters, the replacement of cast iron mains and the replacement and cathodic protection of bare steel mains. In recognition of the significant capital expenditures associated with this safety program, the MPSC initially permitted the deferral and subsequent recovery through rates of depreciation expense, property taxes and associated carrying costs over a ten-year period. On August 28, 2003, the state of Missouri passed certain statutes that provided Missouri Gas Energy the ability to adjust rates periodically to recover depreciation expense, property taxes and carrying costs associated with the Missouri Safety Program, as well as investments in public improvement projects. The continuation of the Missouri Safety Program will result in significant levels of future capital expenditures.

Financing Activities

Summary

The Company continues to pursue opportunities to enhance its credit profile by reducing its ratio of total debt to total capital. At March 31, 2007, the Company’s ratio of total debt to total capital was 61 percent. The issuance of common stock, equity units and preferred stock and use of proceeds therefrom to reduce debt or limit use of debt in conjunction with acquisitions is continued evidence of the Company’s commitment to strengthen its balance sheet and solidify its current investment grade status.

Cash flows used in financing activities were $58.7 million for the three-month period ended March 31, 2007 compared with cash flows provided of $1.44 billion for the same period in 2006. Financing activity cash flow changes were primarily due to net debt retirements of $12.3 million in 2007 versus net debt issuances of $1.49 billion in 2006.

See PART I, ITEM 1. Financial Statements (Unaudited), Note 10 - Debt Obligations, in this Quarterly Report on Form 10-Q for a discussion of the Company’s financing activities and retirement plans related to its $983.3 million of debt maturing through 2008, $111.8 million of which is current.

OTHER MATTERS

Contingencies

See PART I, ITEM 1. Financial Statements (Unaudited), Note 14 - Commitments and Contingencies, in this Quarterly Report on Form 10-Q.

Regulatory

See PART I, ITEM 1. Financial Statements (Unaudited), Note 13 - Regulation and Rates, in this Quarterly Report on Form 10-Q.

Insurance

The Company maintains insurance coverage provided under its policies similar to other comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that do not fully compensate the Company for all losses. Insurance deductibles range from $100,000 to $5 million for the various policies utilized by the Company. Effective June 1, 2007, insurance deductibles for the Company’s policies will range from $100,000 to $10 million. Furthermore, as the Company renews its policies, it is possible that full insurance coverage may not be obtainable on commercially reasonable terms due to recent more restrictive insurance markets.

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, 2006, 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.

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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, 2007.

Changes in Internal Controls.

Management’s assessment of internal control over financial reporting as of December 31, 2006 was included in Southern Union’s Annual Report on Form 10-K filed on March 1, 2007.

There have been no changes in internal control over financial reporting that occurred during the first three months of 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting, except as described below.

During the first quarter of 2007, the Company continued the process of migrating Southern Union Gas Services to its enterprise-wide general ledger and financial reporting system, including subsystems. The system migration is expected to be completed by the end of the third quarter of 2007. Southern Union Gas Services is currently subject to the Company’s internal controls over financial reporting and will be included in management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007.

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.

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 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

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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 such as Hurricanes Katrina and Rita;

·   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;

·   risks relating to Southern Union’s acquisition of the Sid Richardson Energy Services business, including without limitation, the Company’s increased indebtedness resulting from that acquisition and the Company’s increased exposure to highly competitive commodity businesses;

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

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

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

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

·   changes in the ratings of the debt securities of Southern Union or any of its subsidiaries;

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

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

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

·   other risks and unforeseen events.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in PART I, ITEM 1. Financial Statements (Unaudited), Note 14 - 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, 2006.

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 14 - Commitments

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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, 2006.

ITEM 1A. RISK FACTORS.

Except for the additional risk factor information described below associated with the Company’s Distribution segment, there have been no material changes to the risk factors previously disclosed in the Company’s Form 10-K filed with the SEC on March 1, 2007. The following additional risk factor information associated with the Distribution segment should be read in conjunction with the related disclosure in PART I, ITEM 1A. Risk Factors, in Southern Union’s Annual Report on Form 10-K for the year ended December 31, 2006.

The distribution business’ operating results and liquidity needs are seasonal in nature and may fluctuate based on weather conditions and natural gas prices.

Effective April 3, 2007, the MPSC approved distribution rates for Missouri Gas Energy’s residential customers (which comprise approximately 85 percent of its total customers and approximately 65 percent of its margin revenues) that eliminate the impact of weather and conservation for residential margin revenues and related earnings in Missouri.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

N/A

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

N/A

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 1 2007, Southern Union held its Annual Meeting of Stockholders. Each of the proposals submitted to shareholder vote received the required votes necessary for approval. The following matters were voted on by Southern Union’s shareholders:

(I) A proposal to elect nine directors to serve until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Nominee	Total Votes For	Total Votes Withheld
David L Brodsky	103,651,223	1,621,956
Frank W. Denius	104,004,461	1,268,718
Kurt A. Gitter	100,577,057	1,842,786
Herbert H. Jacobi	103,965,539	1,307,640
Adam M. Lindemann	70,585,399	34,687,780
George L. Lindemann	104,027,679	1,245,500
Thomas N. McCarter, III	103,930,184	1,342,995
George Rountree, III	102,498,138	2,775,041
Allan D. Scherer	103,383,886	1,889,293

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(II) A proposal to ratify the appointment of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2007.

For	104,396,842
Against	744,777
Abstain	131,560
Non-votes	0

ITEM 5. OTHER INFORMATION

All information required to be reported on Form 8-K for the quarter ended March 31, 2007 was appropriately reported.

ITEM 6. EXHIBITS

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

2(a) Purchase Agreement among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated as of June

         24, 2004. (Filed as Exhibit 99.b to Southern Union’s Current Report on Form 8-K filed on June 25, 2004 and incorporated herein by reference.)

2(b)Amendment No. 1 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and

         Enron Corp., dated September 1, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)

2(c) Amendment No. 2 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and

         Enron Corp., dated November 10, 2004. (Filed as Exhibit 2.c to Southern Union’s Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)

2(d) Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated as of September 16, 2004. (Filed as Exhibit 10.a to Southern Union’s Current Report on Form 8-K filed

         on September 17, 2004 and incorporated herein by reference.)

2(e)Escrow Agreement attached as Exhibit B to the Order of the United States Bankruptcy Court for the Southern District of New York dated September 10, 2004 (Filed as Exhibit

        10.c to Southern Union’s Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)

2(f)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(g) 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(h)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(i)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

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       February 17, 2006 and incorporated herein by reference.)

2(j)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(k)First Amendment to the Purchase and Sale Agreement between Southern Union Company and National Grid USA, dated as of August 24, 2006(Filed as Exhibit 10.3 to Southern

        Union’s Current Report on Form 8-K filed on August 30, 2006 and incorporated herein by reference.)

        3(a)Amended and Restated Certificate of Incorporation of Southern Union Company (Filed as Exhibit 3(a) to Southern Union’s Annual Report on Form 10-K 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.)

        4(b)Indenture between 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 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 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 JP Morgan Chase Bank (assuccessor 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

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                     Exhibit 4.1 to Southern Union’s Form 8-K/A dated October 24, 2006 and incorporated herein by reference.)

4(i) 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)Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and Trunkline LNG Company, LLC, as guarantors, the

          financial institutions listed therein and Bayerische 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(b)Credit Agreement between Trunkline LNG Holdings, LLC, as borrower, Panhandle Eastern Pipe Line Company, LP and CrossCountry Citrus, LLC, as guarantors, the financial

          institutions listed therein and Bayerische Hypo- Und Vereinsbank AG, New York Branch, as administrative agent, dated as of December 1, 2006. (Filed as Exhibit 10.1 to

          Southern Union’s Current Report on Form 8-K filed on December 7, 2006 and incorporated herein by reference.)

10(c)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(d)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(e)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(f)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(g)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(h)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(i)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(j)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(k)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(l)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(m)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(n)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(o)Form of Long Term Incentive Award Agreement, dated December 28, 2006, between Southern Union Company and the undersigned. (Filed as Exhibit 99.1 to Southern Union’s

          Form 8-K dated January 3, 2007 and incorporated herein by reference.)

10(p) 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 Annual Report on Form 10-K filed on March 1, 2007 and

          incorporated herein by reference.)

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

          reference.)

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

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

21      Subsidiaries of the Registrant. (Filed as Exhibit 21 to Southern Union’s Annual Report on Form 10-K filed on March 1, 2007 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 10, 2007	By /s/ GEORGE E. ALDRICH
	George E. Aldrich                      Vice President and Controller                      (authorized officer and principal                                                                                                          accounting officer)

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