10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C.  20549

____________________________

FORM 10-Q

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

For the quarterly period ended

September 30, 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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securi­ties Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  P  No___

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 November 2, 2007 was 120,032,605.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

September 30, 2007

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)
ITEM 1. Financial Statements (Unaudited):
Condensed consolidated statement of operations	2-3
Condensed consolidated balance sheet	4-5
Condensed consolidated statement of cash flows	6
Condensed consolidated statement of stockholders’ equity and comprehensive income	7
Notes to condensed consolidated financial statements.	8
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	37
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.	50
ITEM 4. Controls and Procedures.	50
PART II. OTHER INFORMATION:
ITEM 1. Legal Proceedings.	52
ITEM 1A. Risk Factors.	52
ITEM 2.  Unregistered Sales of Equity Securities and Use of Proceeds.	52
ITEM 3.  Defaults Upon Senior Securities.	52
ITEM 4.  Submission of Matters to a Vote of Security Holders.	52
ITEM 5.  Other Information.	52
ITEM 6.  Exhibits.	53
SIGNATURES	57

1

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED)

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Three months ended September 30,
	2007			2006
	(In thousands, except per share amounts)
Operating revenues (Note 15)	$	525,473		$	564,418
Operating expenses:
Cost of gas and other energy		261,324			338,730
Operating, maintenance and general		108,478			102,775
Depreciation and amortization		44,900			40,279
Revenue-related taxes		3,804			3,191
Taxes, other than on income and revenues		9,987			9,482
Total operating expenses		428,493			494,457
Operating income		96,980			69,961
Other income (expenses):
Interest expense		(50,703	)		(56,929	)
Earnings from unconsolidated investments		24,820			19,257
Other, net		(1,961	)		(810	)
Total other income (expenses), net		(27,844	)		(38,482	)
Earnings from continuing operations before income taxes		69,136			31,479
Federal and state income tax expense (Note 12)		23,853			19,650
Earnings from continuing operations		45,283			11,829
Discontinued operations (Note 16):
Losses from discontinued operations before income taxes		-			(27,438	)
Federal and state income tax expense (Note 12)		-			147,035
Loss from discontinued operations		-			(174,473	)
Net earnings (loss)		45,283			(162,644	)
Preferred stock dividends		(4,342	)		(4,341	)
Net earnings (loss) available for common stockholders	$	40,941		$	(166,985	)
Net earnings available for common stockholders from
continuing operations per share:
Basic	$	0.34		$	0.06
Diluted		0.34			0.06
Net earnings (loss) available for common stockholders per share:
Basic	$	0.34		$	(1.44	)
Diluted		0.34			(1.42	)
Dividends declared on common stock per share		0.10			0.10
Weighted average shares outstanding  (Note 5):
Basic		120,018			115,801
Diluted		120,759			117,786

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

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(UNAUDITED)

	Nine months ended September 30,
	2007			2006
	(In thousands, except per share amounts)
Operating revenues (Note 15)	$	1,893,754		$	1,663,939
Operating expenses:
Cost of gas and other energy		1,069,035			975,629
Operating, maintenance and general		318,982			279,910
Depreciation and amortization		132,030			109,800
Revenue-related taxes		26,498			23,564
Taxes, other than on income and revenues		33,235			32,436
Total operating expenses		1,579,780			1,421,339
Operating income		313,974			242,600
Other income (expenses):
Interest expense		(154,034	)		(162,128	)
Earnings from unconsolidated investments		81,986			46,656
Other, net		1,800			37,833
Total other income (expenses), net		(70,248	)		(77,639	)
Earnings from continuing operations before income taxes		243,726			164,961
Federal and state income tax expense  (Note 12)		68,747			63,392
Earnings from continuing operations		174,979			101,569
Discontinued operations (Note 16):
Earnings from discontinued operations before income taxes		-			6,111
Federal and state income tax expense  (Note 12)		-			158,642
Loss from discontinued operations		-			(152,531	)
Net earnings (loss)		174,979			(50,962	)
Preferred stock dividends		(13,024	)		(13,023	)
Net earnings (loss) available for common stockholders	$	161,955		$	(63,985	)
Net earnings available for common stockholders from
continuing operations per share:
Basic	$	1.35		$	0.78
Diluted		1.34			0.76
Net earnings (loss) available for common stockholders per share:
Basic	$	1.35		$	(0.57	)
Diluted		1.34			(0.55	)
Dividends declared on common stock per share		0.30			0.30
Weighted average shares outstanding  (Note 5):
Basic		119,894			113,150
Diluted		120,622			116,139

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

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

ASSETS

	September 30,			December 31,
	2007			2006
	(In thousands)
Current assets:
Cash and cash equivalents	$	19,739		$	5,751
Accounts receivable, net of allowances of
$3,822 and $4,830, respectively		212,906			298,231
Accounts receivable – affiliates		11,174			3,546
Inventories  (Note 4)		278,559			241,137
Deferred gas purchase costs		28,193			-
Gas imbalances - receivable		80,890			69,877
Prepayments and other assets		30,894			72,317
Total current assets		662,355			690,859
Property, plant and equipment:
Plant in service		5,171,233			5,025,631
Construction work in progress		465,556			178,935
		5,636,789			5,204,566
Less accumulated depreciation and amortization		(741,281	)		(620,139	)
Net property, plant and equipment		4,895,508			4,584,427
Deferred charges:
Regulatory assets  (Note 6)		66,151			65,865
Deferred charges		62,213			61,602
Total deferred charges		128,364			127,467
Unconsolidated investments  (Note 7)		1,243,548			1,254,749
Goodwill		89,227			89,227
Other		29,736			36,061
Total assets	$	7,048,738		$	6,782,790

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

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEET

(UNAUDITED)

STOCKHOLDERS' EQUITY AND LIABILITIES

	September 30,			December 31,
	2007			2006
	(In thousands)
Stockholders’ equity:
Common stock, $1 par value; 200,000 shares authorized;
121,090 shares issued at September 30, 2007	$	121,090		$	120,718
Preferred stock, no par value; 6,000 shares authorized;
920 shares issued at September 30, 2007		230,000			230,000
Premium on capital stock		1,783,005			1,775,763
Less treasury stock: 1,063 and 1,059
shares, respectively, at cost		(27,839	)		(27,708	)
Less common stock held in trust: 779
and 863 shares, respectively		(14,955	)		(14,628	)
Deferred compensation plans		15,018			14,691
Accumulated other comprehensive loss (Note 3)		(8,596	)		(901	)
Retained earnings (deficit)		78,459			(47,527	)
Total stockholders' equity		2,176,182			2,050,408
Long-term debt obligations  (Note 10)		2,571,447			2,689,656
Total capitalization		4,747,629			4,740,064
Current liabilities:
Long-term debt and capital lease obligation
due within one year  (Note 10)		540,117			461,011
Notes payable  (Note 10)		230,000			100,000
Accounts payable and accrued liabilities		169,909			300,762
Federal, state and local taxes payable		36,496			30,828
Accrued interest		42,224			46,342
Customer deposits		16,571			14,670
Deferred gas purchases		1,865			15,551
Gas imbalances - payable		213,142			146,995
Other		179,878			84,665
Total current liabilities		1,430,202			1,200,824
Deferred credits		212,253			224,725
Accumulated deferred income taxes		658,654			617,177
Commitments and contingencies  (Note 14)
Total stockholders' equity and liabilities	$	7,048,738		$	6,782,790

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

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2007			2006
	(In thousands)
Cash flows provided by (used in) operating activities:
Net earnings (loss)	$	174,979		$	(50,962	)
Adjustments to reconcile net earnings to net cash flows
provided by operating activities:
Depreciation and amortization		132,030			111,839
Amortization of debt expense		556			10,467
Deferred income taxes		50,808			183,024
Loss on disposition of operations		-			48,591
Provision for bad debts		13,574			23,137
Impairment of assets		-			25,940
Loss (gain) on derivatives		1,227			(41,846	)
Earnings from unconsolidated investments, net of cash distributions		11,889			(46,656	)
Other		1,675			(553	)
Changes in operating assets and liabilities, net of acquisitions		1,982			65,748
Net cash flows provided by operating activities		388,720			328,729
Cash flows provided by (used in) investing activities:
Additions to property, plant and equipment		(382,123	)		(232,046	)
Acquisitions of operations, net of cash received		-			(1,537,627	)
Return of investment in Citrus (Note 7)		9,674			-
Dispositions of operations, net		(49,304	)		1,076,738
Other		3,501			4,640
Net cash flows used in investing activities		(418,252	)		(688,295	)
Cash flows provided by (used in) financing activities:
Decrease in book overdraft		(2,139	)		(24,623	)
Issuance costs of debt		(2,418	)		(9,195	)
Issuance of common stock		-			125,000
Issuance of long-term debt		455,000			-
Dividends paid on common stock		(35,933	)		(22,371	)
Dividends paid on preferred stock		(13,024	)		(8,682	)
Repayment of debt obligation		(493,316	)		(1,090,000	)
Issuance of bridge loan		-			1,600,000
Net change in revolving credit facilities		130,000			(225,000	)
Proceeds from exercise of stock options		3,592			8,487
Tax benefit on stock option exercises		1,758			1,773
Other		-			(5,770	)
Net cash flows provided by financing activities		43,520			349,619
Change in cash and cash equivalents		13,988			(9,947	)
Cash and cash equivalents at beginning of period		5,751			16,938
Cash and cash equivalents at end of period	$	19,739		$	6,991

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

6

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		-		-		-			-			-			-			-			174,979			174,979
Unrealized loss on hedging																								-
activities, net of tax		-		-		-			-			-			-			(4,249	)		-			(4,249	)
Change in fair value of hedging																								-
derivatives, net of tax		-		-		-			-			-			-			(3,288	)		-			(3,288	)
Recognized actuarial gain (loss)
and prior service credit (cost),
net of tax		-		-		-			-			-			-			(158	)		-			(158	)
Comprehensive income																								167,284
Preferred stock dividends		-		-		-			-			-			-			-			(13,024	)		(13,024	)
Cash dividends declared		-		-		-			-			-			-			-			(35,969	)		(35,969	)
Share-based compensation		-		-		2,263			-			-			-			-			-			2,263
Restricted stock issuances		107		-		(107	)		(131	)		-			-			-			-			(131	)
Exercise of stock options		265		-		5,086			-			-			-			-			-			5,351
Contributions to Trust		-		-		-			-			(639	)		639			-			-			-
Disbursements from Trust		-		-		-			-			312			(312	)		-			-			-
Balance September 30, 2007	$	121,090	$	230,000	$	1,783,005		$	(27,839	)	$	(14,955	)	$	15,018		$	(8,596	)	$	78,459		$	2,176,182

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.

7

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, which are included in the Company’s Form 10-K filed with the SEC.  The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with GAAP and reflect adjustments that are, in the opinion of management, necessary for a fair statement of results for the interim period.  The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.  Due to the seasonal nature of the Company’s operations, the results of operations and cash flows for any interim period are not necessarily indicative of the results that may be expected for the full year.  Certain 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 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, FIN 48 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 was 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.

FSP No. FIN 48-1, “Definition of ’Settlement’ in FASB Interpretation No. 48” (FIN 48-1):  Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits.  The Company’s adoption of FIN 48, effective January 1, 2007, was consistent with FIN 48-1.

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.

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FIN 39-1):  Issued by the FASB in April 2007, FIN 39-1 impacts entities that enter into master netting arrangements as part of their derivative transactions by allowing net derivative positions to be offset in the financial statements against the fair value of amounts (or amounts that approximate fair value) recognized for the right to reclaim cash collateral or the obligation to return cash collateral under those arrangements.  FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  The Company is currently evaluating the impact of FIN 39-1 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						Nine Months Ended
	September 30,						September 30,
Other Comprehensive Income (Loss)	2007			2006			2007			2006
	(In thousands)						(In thousands)
Net earnings (loss)	$	45,283		$	(162,644	)	$	174,979		$	(50,962	)
Other Comprehensive Income (Loss) Adjustments:
Change in fair value of interest rate hedges, net
of tax of $(4,329), $0, $(1,374) and $0, respectively		(6,319	)		-			(1,924	)		-
Reclassification of unrealized gain on interest
rate hedges into earnings, net of tax of
$(34), $(33), $115 and $(103), respectively		(143	)		(34	)		(946	)		(107	)
Reversal of minimum pension liability related to
disposition, net of tax of $0, $16,004, $0		-			26,331			-			26,331
and $16,004, respectively.
Change in fair value of commodity hedges, net of
tax of $1,156, $5,583, $(828) and $7,175, respectively		1,906			9,203			(1,364	)		11,880
Reclassification of unrealized gain on
commodity hedges into earnings, net of tax of $(829),
($1,201), $(2,004) and ($1,456), respectively		(1,366	)		(2,024	)		(3,303	)		(2,452	)
Reclassification of actuarial gain and prior
service credit (cost) relating to pension and other
postretirement benefits into earnings, net of tax
of $(880), $0, $(381) and $0, respectively		(1,341	)		-			(158	)		-
Total other comprehensive income (loss)		(7,263	)		33,476			(7,695	)		35,652
Total comprehensive income (loss)	$	38,020		$	(129,168	)	$	167,284		$	(15,310	)

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	September 30,			December 31,
Components in Accumulated Other Comprehensive Income (Loss)	2007			2006
	(In thousands)
Interest rate hedges, net	$	(5,182	)	$	(2,312	)
Commodity hedges, net		609			5,276
Benefit Plans:
Net actuarial loss and prior service costs, net - pensions		(22,719	)		(26,678	)
Net actuarial gain and prior service credit, net - other postretirement benefits		18,696			22,813
Total Accumulated other comprehensive loss, net of tax	$	(8,596	)	$	(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 September 30, 2007 was $153.3 million, or 21,617,000 million British thermal units (MMBtu), of which $12 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 $14 million and $13.2 million at September 30, 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.  Materials and supplies in the Gathering and Processing segment, primarily comprised of compressor components and parts, were $6.3 million and $6.9 million at September 30, 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 September 30, 2007 and December 31, 2006 was $113.3 million and $103.5 million, respectively, and consisted of 18,327,112 MMBtu and 14,702,000 MMBtu, respectively.  Materials and supplies inventories in the Distribution segment were $3.7 million and $3.7 million at September 30, 2007 and December 31, 2006, respectively.

10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

5. Earnings per Share

Basic earnings per share is computed based on the weighted-average number of common shares outstanding during each period.  Diluted earnings per share is computed based on the weighted-average number of common shares outstanding during each period, increased by common stock equivalents from stock options, restricted stock, 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				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(In thousands)				(In thousands)
Weighted average shares outstanding - Basic		120,018		115,801		119,894		113,150
Add assumed vesting of restricted stock		41		40		30		122
Add assumed conversion of equity units		270		1,383		227		2,021
Add assumed exercise of stock options
and stock appreciation rights		430		562		471		846
Weighted average shares outstanding - Dilutive		120,759		117,786		120,622		116,139

There were no anti-dilutive options outstanding for the periods presented above.

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:

	September 30,		December 31,
Regulatory Assets	2007		2006
	(In thousands)
Pension and Postretirement Benefits	$	35,215	$	33,969
Environmental		20,302		15,571
Missouri Safety Program		6,347		8,751
Other		4,287		7,574
	$	66,151	$	65,865

The Company’s regulatory assets at September 30, 2007 relating to Distribution segment operations that are being recovered through current rates totaled $45.4 million.  The Company expects that the $20.7 million of regulatory assets not currently in rates will be included in its rates as rate cases occur in the future.  The remaining recovery period associated with these assets ranged from 3 months to 96 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 12 months to 93 months.

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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:

	September 30,		December 31,
Unconsolidated Investments	2007		2006
	(In thousands)
Equity investments:
Citrus	$	1,221,967	$	1,233,172
Other		20,806		20,802
Investments at cost		775		775
	$	1,243,548	$	1,254,749

Equity Investments.  Unconsolidated investments at September 30, 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 (Grey Ranch), Lee 8 Partnership and PEI II, LLC, respectively.  The Company accounts for these investments using the equity method.  The Company’s share of net earnings or loss from these equity investments is recorded in Earnings from unconsolidated investments in the Condensed Consolidated Statement of Operations.

Dividends.  During the three- and nine-month periods ended September 30, 2007, Citrus paid dividends of $27.4 million and $103.6 million, respectively, to the Company, of which $9.7 million has been reflected by the Company as a return of investment.  In the three- and nine-month periods ended September 30, 2006, Citrus paid CCE Holdings, LLC (CCE Holdings) dividends of $18.6 million and $49 million, respectively.  CCE Holdings did not distribute dividends to the Company in the same 2006 periods.

12

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
	September 30, 2007				September 30, 2006
			Other Equity		CCE						Other
	Citrus		Investments		Holdings (1)						Investments
Income Statement Data:	(In thousands)
Revenues	$	136,800	$	4,115	$	-				$	2,484
Operating income (loss)		84,686		1,554		(1,474	)				561
Equity earnings		-		-		21,660		(2	)		-
Income from discontinued
operations		-		-		25,195		(3	)		-
Net income		42,177		1,532		38,737					522
	Nine Months Ended				Nine Months Ended
	September 30, 2007				September 30, 2006
			Other Equity		CCE					Other Equity
	Citrus		Investments		Holdings (1)					Investments
	(In thousands)
Income Statement Data:
Revenues	$	375,357	$	8,848	$	-				$	5,330
Operating income (loss)		218,132		2,879		(4,603	)				880
Equity earnings		-		-		57,292		(2	)		-
Income from discontinued								(3	)
operations		-		-		61,111					-
Net income		126,438		3,725		94,044					772

_____________________

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

(2)  Represents equity earnings of CCE Holdings in Citrus prior to becoming a wholly-owned subsidiary on December 1, 2006.

(3)  Income from discontinued operations for CCE Holdings relates primarily to the operations of Transwestern Pipeline Company, LLC

      (Transwestern).

13

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, whose principal remaining asset is 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 $614.8 million and $585.6 million as of September 30, 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 September 30, 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		(541	)	N/A
Goodwill  (2)		664,609		N/A
Sub-total		581,344
Accumulated net accretion to equity earnings		33,415
Net investment in excess of underlying equity	$	614,759

____________________

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

(2) The Company’s tax basis in the investment in Citrus includes the equity goodwill.  See “Goodwill Evaluation” below.

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 of contamination resulting from past releases of hydrocarbons and chlorinated compounds at certain sites on its gas transmission systems.  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 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 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, was approximately $664.6million and $642.2 million at September 30, 2007 and December 31, 2006, respectively.  The amount recorded for goodwill at September 30, 2007 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

14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 its condensed consolidated balance sheet, resulting in an impact to the Company’s share of its equity earnings.  Florida Gas’ regulatory asset and liability balances at September 30, 2007 were $17.4 million and $15.1 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 rule 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.  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 with certainty 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 2012.

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.  The first phase of the turnpike project includes 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 $95 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 rights-of-way.  The total miles of pipe that may ultimately be affected by all of the FDOT/FTE widening projects, and any associated relocation and/or right-of-way costs, cannot be determined at this time.

Under certain conditions, existing agreements between Florida Gas and the FDOT/FTE require the FDOT/FTE to provide any new rights-of-way needed for relocation of the pipelines and 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 the FDOT/FTE in the Seventeenth Judicial Circuit, Broward County, Florida, seeking relief with respect to three specific sets of FDOT/FTE widening projects in Broward County.  The complaint seeks damages for breach of easement and relocation agreements for the one set of projects on which construction has already commenced, and injunctive relief as well as damages for the two other sets of projects on which construction has yet to commence.  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 and a subsequent FDOT/FTE motion for reconsideration were denied in April 2007.  On April 24, 2007, the FDOT/FTE filed a complaint against Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, seeking a declaratory judgment that, under existing agreements, Florida Gas is liable for the costs of relocation associated with such projects and is not entitled to certain other rights.  On August 7, 2007, the Orange County Court granted a motion by Florida Gas to abate and stay the Orange County action.

On October 24, 2007, Florida Gas filed a complaint in the US District Court of the Northern District of Florida, Tallahassee Division, against Stephanie C. Kopelousos (Kopelousos) in her official capacity as the Secretary of the Florida Department of Transportation, seeking to enjoin Kopelousos from violating federal law in connection with construction of the FDOT/FTE Golden Glades project, a new toll plaza in Miami-Dade County, Florida.

15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Florida Gas seeks a declaratory judgment that certain Florida statutes are preempted by federal law to the extent such state statutes purport to regulate the abandonment or relocation schedule for the federally regulated pipelines of Florida Gas and prospective preliminary and permanent injunctive relief enjoining Kopelousos from proceeding with construction on the Golden Glades project over and around such pipelines.

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, 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 $7.6 million gain recorded in Earnings from unconsolidated investments in the Condensed Consolidated Statement of Operations.

Citrus Enron Bankruptcy Receivable.  Citrus previously filed bankruptcy related claims against an Enron-affiliated bankrupt company.  The parties 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 sold the receivable claim in the second quarter of 2007 to a third-party for $11.4 million, resulting in a gain.  Earnings from unconsolidated investments includes $5.7 million of the gain ($3.6 million, net of tax), representing the Company’s 50 percent equity share of the gain.

Litigation.

Jack Grynberg.  Jack Grynberg, an individual, filed actions for damages against a number of companies, including Florida Gas, alleging mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  For additional information related to these filed actions, see Note 14– Commitments and Contingencies – Litigation.

8. Stockholders’ Equity

Dividends.  On October 12, 2007, July 13, 2007 and 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 each were paid to holders of record as of September 28, 2007, June 29, 2007 and March 30, 2007.

 9. Derivative Instruments and Hedging Activities

Interest Rate Swaps and Treasury Locks.  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 to 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.

16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In August and September 2007, Panhandle Eastern Pipe Line Company, LP (PEPL) entered into a series of treasury rate locks with an aggregate notional amount of $300 million to manage its exposure against changes in future interest payments attributable to changes in the 10-year US treasury rate prior to the anticipated issuance of fixed-rate debt.  The weighted-average interest rate of these treasury rate locks is 4.57 percent.  PEPL entered into treasury rate locks that fixed the benchmark component of the interest rate to be established for the forecasted October 2007 issuance of $300 million fixed-rate debt. The treasury rate locks are accounted for as cash flow hedges, and PEPL recorded a $338,000 gain ($207,000, net of tax), in Accumulated other comprehensive loss with respect to the treasury rate locks as of September 30, 2007. The treasury rate locks were settled on October 23, 2007 with PEPL paying approximately $3.9 million. The $3.9 million pre-tax loss will be included in Accumulated other comprehensive loss during the fourth quarter of 2007 and will be recognized in earnings as an adjustment to interest expense over the ten-year term of the $300 million 6.20 percent senior notes due November 1, 2017. See Note 18 – Subsequent Event.

PEPL’s subsidiary, Trunkline LNG Holdings, LLC (LNG Holdings) has entered into interest rate swap agreements with an aggregate notional amount of $455 million that effectively fix the interest rate applicable to the floating rate of the $455 million Term Loan due in 2012, from June 15, 2007 through March 13, 2012, and qualify for hedge accounting.  For the period from June 15, 2007 through September 30, 2007, there was no swap ineffectiveness.  As of September 30, 2007, floating rate LIBOR-based interest payments were exchanged for weighted average fixed rate interest payments of 4.98 percent plus a credit spread of 0.625 percent, based upon PEPL’s credit rating for its senior unsecured debt.  As of September 30, 2007, the fair value position of the swaps was a liability of $4.2 million and is included in Deferred credits in the Condensed Consolidated Balance Sheet.  For the three- and four-month periods ended September 30, 2007, an unrealized loss of $11.5 million ($6.9 million, net of tax) and $4.2 million ($2.5 million, net of tax), respectively, was included in Accumulated other comprehensive loss related to the change in fair value of these swaps.  Current market pricing models were used to estimate fair values of interest rate swap agreements.

On April 29, 2005, the Company refinanced the existing bank loans of 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 loss during the second quarter of 2005 and was amortized to interest expense through January 2007.

In March 2004, PEPL 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.

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 loss and is being amortized into interest expense over the lives of the associated debt instruments.  As of September 30, 2007, approximately $897,000 of net after-tax losses in Accumulated other comprehensive loss will be amortized into interest expense during the next twelve months.

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 transacting with counterparties and their ability to meet the terms of the contracts but also the risk associated with unmatched positions and market fluctuations.  The Company is required to record 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.

17

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 puts, fixed-price physical forward contracts, exchange-traded futures, 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- and nine-month periods ended September 30, 2007, the Company recorded a gain of $198,000 and a loss of $135,000, respectively, for its non-hedging activities, nil of which gain and $555,000 of which loss are related to the crude oil puts for the same periods.  For the three- and nine-month periods ended September 30, 2006, the Company recorded a gain of $151,000 and a loss of $1.7 million, respectively, for its non-hedging activities.

Commodity-Based 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 the Sid Richardson Energy Services business 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.  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 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 Commodity-Based Cash Flow Hedges.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007			2006
	(In thousands)					(In thousands)
Change in fair value of commodity hedges - increase
(decrease) in Accumulated other comprehensive
loss, net of tax of $1,156, $5,583, $(828),
and $7,175, respectively	$	1,906	$	9,203		$	(1,364	)	$	11,880
Reclassification of unrealized gain on
commodity hedges - increase of
Operating revenues, excluding tax effect of $829,
$1,201, $2,004, and $1,456, respectively		2,195		3,225			5,307			3,908
Gain (loss) realized upon cash settlement - increase
(decrease) of Operating revenues		166		466			(603	)		577
Loss on ineffectiveness of commodity hedges		-		(1,667	)		-			(1,878	)
Cash realized on settlement of commodity hedges		10,017		21,463			26,529			49,944

At September 30, 2007 and December 31, 2006, the Company reported in the Condensed Consolidated Balance Sheet in Prepayments and other assets, derivative asset balances of $8.8 million and $38.1 million, respectively.  During 2007, the Company expects that all of the $978,000 ($608,000, net of tax) gain included in the Accumulated other comprehensive loss balance at September 30, 2007 will be reclassified into earnings.

18

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 September 30, 2007 and December 31, 2006, the fair values of the contracts, which expire at various times through August 2009, are included in the Condensed Consolidated Balance Sheet as assets and liabilities, with matching adjustments to deferred cost of gas of $20.7 million and $19 million, respectively.

19

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 PEPL and its subsidiaries (collectively, Panhandle) under their respective notes, debentures and bonds at the dates indicated:

	September 30,		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 to 2027		19,500		19,500
4.375% Senior Notes due 2008		100,000		100,000
6.15% Senior Notes due 2008		125,000		125,000
7.20% 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 2012  (1)		427,309		465,000
Term Loan due 2012		455,000		-
Net premiums on long-term debt		7,562		9,613
		1,607,299		1,647,667
Total Long-Term Debt Obligations		3,111,564		3,151,932
Credit Facilities		230,000		100,000
Total consolidated debt obligations		3,341,564		3,251,932
Less fair value swaps of Panhandle		-		1,265
Less current portion of long-term debt  (2)		540,117		461,011
Less short-term debt		230,000		100,000
Total consolidated long-term debt obligations	$	2,571,447	$	2,689,656

(1)  At December 31, 2006, this Term Loan was due in 2008.  See the following LNG Holdings Term Loans discussion for information related to the extension of the maturity date from April 4, 2008 to June 29, 2012.

(2)  Includes nil and $1.3 million of fair value of swaps related to debt classified as current at September 30, 2007 and December 31, 2006, respectively.

Southern Union has $3.11 billion of long-term debt, including net premiums of $7.6 million, recorded at September 30, 2007, of which $540.1 million is current.  Debt of $2.68 billion is at fixed rates ranging from 4.38 percent to 9.44 percent.  Southern Union also has floating-rate debt totaling $427.3 million, bearing an interest rate of 5.68 percent as of September 30, 2007.

20

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of September 30, 2007, the Company has scheduled long-term debt payments, excluding credit facility payments, as follows:

	Remainder										2012 and
	2007		2008		2009		2010		2011		thereafter
	(In thousands)
Southern Union	$	-	$	225,000	$	-	$	-	$	-	$	1,279,265
Panhandle		15,117		300,000		60,623		40,500		-		1,183,497
Total	$	15,117	$	525,000	$	60,623	$	40,500	$	-	$	2,462,762

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.  As of September 30, 2007, the Company was in compliance with all debt covenants.  None of the Company’s long-term debt is cross-collateralized and most of its long-term debt obligations contain cross-default provisions.

See Note 18 – Subsequent Event for information related to $300 million fixed rate debt issued in October 2007.

LNG Holdings Term Loans.  On June 29, 2007, LNG Holdings, an indirect wholly-owned subsidiary of the Company, as borrower, and PEPL and CrossCountry Citrus, LLC (CrossCountry Citrus), each an indirect wholly-owned subsidiary of the Company, as guarantors, entered into an amended and restated term loan facility (Amended Credit Agreement).  The Amended Credit Agreement amends the $465 million term loan facility, dated as of December 1, 2006, by and among LNG Holdings, as the borrower, and PEPL and CrossCountry Citrus, as guarantors.  The Amended Credit Agreement extended the maturity of the term loan from April 4, 2008 to June 29, 2012, and decreased the interest rate from LIBOR plus 87.5 basis points to LIBOR plus 55 basis points, based upon the current credit rating of PEPL's senior unsecured debt.  The balance of the term loan facility at September 30, 2007 is $427.3 million.

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 senior unsecured debt.  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.  See Note 9 – Derivative Instruments and Hedging Activities – Interest Rate Swaps for information regarding interest rate swaps on the 2012 Term Loan.

Credit Facilities.  Balances of $230 million and $100 million were outstanding under the Company’s credit facilities at effective interest rates of 5.99 percent and 6.02 percent at September 30, 2007 and December 31, 2006, respectively.  The Company classifies its borrowings under the credit facilities due May 28, 2010 as short-term debt, as the individual borrowings are generally for periods of 15 to 180 days.  At maturity, the Company may (i) retire the outstanding balance of each borrowing with available cash on hand and/or proceeds from a new borrowing, or (ii) at the Company’s option, extend the borrowing’s maturity date for up to an additional 90 days.  As of November 2, 2007, there was a balance of $26 million outstanding under the Company’s credit facilities, with an effective interest rate of 5.24 percent.

Retirement of Debt Obligations

The Company plans to refinance with new debt or bank financings the majority of its $525 million of debt maturing in 2008.  Alternatively, the Company may retire such debt with proceeds from one or a combination of the following sources: (i) cash flows from operating activities; (ii) borrowings under existing credit facilities; and (iii) new equity offering(s).  The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital markets, current economic and capital market conditions and market expectations regarding the Company’s future earnings and cash flows, that it will be able

21

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

to refinance and/or retire these obligations under acceptable terms within the next year.  There can be no assurance, however, that the Company will be able to achieve acceptable terms in any negotiation of new debt or bank financings.  Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company’s inability to do so would cause a material adverse effect on the Company’s financial condition and liquidity.

11. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the three-month periods ended September 30, 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 $0.4 million for the three-month period ended September 30, 2006.  Net periodic other postretirement benefit costs for discontinued operations totaled $0.1 million for the three-month period ended September 30, 2006.  See Note 16 – Discontinued Operations for additional related 2006 information.

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended						Three Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
Service cost	$	664		$	694		$	489		$	586
Interest cost		2,287			2,246			1,047			975
Expected return on plan assets		(2,382	)		(2,204	)		(719	)		(456	)
Prior service cost amortization		127			147			(732	)		(751	)
Recognized actuarial (gain) loss		1,994			1,812			(204	)		(23	)
Sub-total		2,690			2,695			(119	)		331
Regulatory adjustment		(515	)		(1,983	)		666			666
Net periodic benefit cost	$	2,175		$	712		$	547		$	997

Net periodic benefit cost for the nine-month periods ended September 30, 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 $6.8 million for the nine-month period ended September 30, 2006.  Net periodic other postretirement benefit costs for discontinued operations totaled $1.6 million for the nine-month period ended September 30, 2006.  See Note 16 – Discontinued Operations for additional related 2006 information.

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands)
Service cost	$	1,992		$	2,080		$	1,467		$	1,757
Interest cost		6,861			6,737			3,141			2,925
Expected return on plan assets		(7,146	)		(6,613	)		(2,157	)		(1,369	)
Prior service cost amortization		381			442			(2,196	)		(2,253	)
Recognized actuarial (gain) loss		5,982			5,437			(612	)		(68	)
Sub-total		8,070			8,083			(357	)		992
Regulatory adjustment		(2,981	)		(5,949	)		1,998			1,998
Net periodic benefit cost	$	5,089		$	2,134		$	1,641		$	2,990

22

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In the Distribution segment, the Company recovers certain qualified pension benefit plan and other

postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act or other utility commission specific guidelines.  The difference between these amounts and periodic benefit cost calculated pursuant to FASB Statement No. 87, Employers' Accounting for Pensions and FASB Statement 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, is deferred as a regulatory asset or liability and amortized to expense over periods, promulgated by the applicable utility commission, in which this difference will be recovered in rates.

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 September 30, 2007 and 2006 was 35 percent and 62 percent, respectively.  The Company’s EITR from continuing operations for the nine-month periods ended September 30, 2007 and 2006 was 28 percent and 38 percent, respectively.

The decrease in the EITR from continuing operations for both the three-month and nine-month periods was primarily due to the following:

· Tax benefits 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 September 30, 2007 and 2006, the tax impact of the dividends received deduction was a benefit of $8.1 million and an expense of $166,000, respectively.  For the nine-month periods ended September 30, 2007 and 2006, the tax benefit of the dividends received deduction was $28.2 million and $4.9 million, respectively; and

· Additional tax expense resulting from nondeductible executive compensation. For the three-month periods ended September 30, 2007 and 2006, the additional tax expense resulting from nondeductible executive compensation was nil and $3.2 million, respectively. For the nine-month periods ended September 30, 2007 and 2006, the additional tax expense resulting from nondeductible executive compensation was approximately $172,000 and $3 million, respectively.

The Company adopted FIN 48 on January 1, 2007.  The implementation of FIN 48 did not have a material impact on the condensed consolidated financial statements and did not require an adjustment to Retained earnings (deficit). 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 three- and nine-month periods ended September 30, 2007.

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 recorded 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 federal penalties assessed as a result of this examination and no significant state penalties associated with the amended tax return filings. The Company paid the applicable interest of $158,000 ($99,000, net of tax) to the IRS, state and local jurisdictions in the third quarter of 2007.  At September 30, 2007, the Company had no remaining state and local interest liabilities.

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.

23

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

13. Regulation and Rates

Panhandle.  The Company has commenced construction of an additional enhancement at its Trunkline LNG terminal.  This infrastructure enhancement project, which was originally expected to cost approximately $250 million, plus capitalized interest, will increase send out flexibility at the terminal and lower fuel costs.  Recent cost projections indicate the construction costs will likely be higher, currently estimated at approximately $335 million, plus capitalized interest.  The negotiated rate with the project’s customer, BG LNG Services, will be adjusted based on final capital costs pursuant to a contractually-based formula.  The project is scheduled to be in operation in late 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 $128.3 million and $40.8 million of costs are included in the line item Construction work-in-progress at September 30, 2007 and December 31, 2006, respectively.

The Company has received approval from FERC to modernize and replace various compression facilities on PEPL.  Such replacements are being made at eleven different compressor stations and are expected to be installed by the end of 2011.  The estimated remaining cost of these replacements is approximately $240 million, plus capitalized interest.  The Company is also replacing approximately 32 miles of existing pipeline on the east end of the PEPL system at a current estimated cost of approximately $80 million, which will further improve system integrity and reliability.  The project is planned to be completed in late 2007.  Approximately $111.7 million and $57.9 million of costs related to these projects are included in the line item Construction work-in-progress at September 30, 2007 and December 31, 2006, respectively.

Trunkline Gas Company, LLC (Trunkline) has commenced construction on a field zone expansion project, which was approved by FERC in April 2007.  The expansion project includes the previously announced north Texas expansion and adding capacity to Trunkline’s pipeline system in Texas and Louisiana to increase deliveries to Henry Hub.  Trunkline will increase the capacity along existing rights-of-way from Kountze, Texas to Longville, Louisiana by approximately 625 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 1 billion cubic feet per day from Kaplan, Louisiana to Henry Hub.  This project has an anticipated in-service date during December 2007.  Recent extremely rainy conditions in the expansion project area have adversely impacted construction activities and will likely increase project costs.  The magnitude of potential cost increases is highly dependent on weather conditions going forward through the project’s ultimate completion.  The Company currently estimates the project will cost approximately $250 million, plus capitalized interest.  Estimated costs include a $40 million contribution in aid of construction (CIAC) to a subsidiary of Energy Transfer Partners, L.P. (Energy Transfer), a non-affiliated entity, upon movement of Energy Transfer’s delivery point to a location originally anticipated to be near Buna, Texas.  Subsequently, Energy Transfer indicated that the Buna route was problematic and, as a result, the parties reached agreement on revised terms for the field zone expansion project, including additional contracted volumes and a delivery point near Silsbee, Texas.  An amended filing was made with FERC on October 2, 2007, reflecting the new delivery point location.  The ultimate return and accounting for the CIAC to Energy Transfer depends on completion of construction by Energy Transfer and the eventual commercial impact on the field zone expansion project.  Approximately $147 million and $12.5 million of costs for this project are included in the line item Construction work-in-progress at September 30, 2007 and December 31, 2006, respectively.

See Note 18 – Subsequent Event for information related to funding sources for the Company’s ongoing capital programs discussed above.

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, a wholly-owned subsidiary of PEPL (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

24

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

for hearing.  Pursuant to FERC order, Southwest Gas Storage filed a cost and revenue study with FERC on February 20, 2007.  On August 1, 2007, Southwest Gas Storage filed a Section 4 rate case requesting an increase in rates.  On August 31, 2007, the FERC accepted Southwest Gas Storage’s rate increase to become effective on February 1, 2008, subject to refund.  This order also consolidated the Section 5 proceeding with the Section 4 rate case.  On October 26, 2007, the Staff of the FERC filed a Motion to Suspend the Procedural Schedule in the pending Southwest Gas Storage rate cases.  The Staff represented that the parties had reached a settlement in principle that would resolve all the issues in the cases.  On October 29, 2007, the Motion was granted.  The parties are now finalizing the settlement documents.  Southwest Gas Storage anticipates filing the settlement with FERC by the end of 2007.   In the event that the terms of the settlement in principle are finalized and approved by FERC, the agreement is not expected to have a material adverse impact on the financial position, results of operations or cash flows of the Company.  No proceeding has been initiated against PEPL or any of its other subsidiaries, but any potential rate reductions from such a proceeding would be expected to be mitigated by the impact of significant ongoing capital spending for pipeline integrity, safety, environmental (including air emissions), compression modernization and other investments.

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 and to acquire 3 Bcf of additional base gas to maintain storage field operations.  This filing brings the certificated capacity in line with operational performance of the field.  On September 7, 2007, the FERC approved Southwest Gas Storage’s North Hopeton field modifications.  Southwest Gas Storage has entered into a third-party agreement to replace this storage capacity effective April 1, 2007 with an initial term of two years.

Sea Robin filed a rate case with FERC in June 2007, requesting an increase in its maximum rates.  Several parties have submitted protests to the rate increase filing with FERC.  On July 30, 2007, FERC suspended the effectiveness of the filed rate increase until January 1, 2008.  The final outcome of the rate case has many variables and potential outcomes and it is impossible to predict its timing or materiality at this time. 

On December 15, 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule defines as 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.  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 with certainty the total scope of required remediation activities prior to completion of the assessments and inspections.  The costs associated with pipeline integrity management, including activity associated with HCAs, are preliminarily estimated to be in the range of approximately $23 million to $30 million per year through 2017.

Missouri Gas Energy.  The Missouri Public Service Commission (MPSC) issued a 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 had recommended the MPSC disallow a total of approximately $47.7 million in gas costs incurred during the period July 1, 1997 through June 30, 2005. By order issued August 2, 2007, the MPSC adopted the MPSC staff’s formal withdrawal of disallowance recommendations totaling approximately $35.3 million, in response to a January 2007 Missouri Supreme Court ruling.  By orders issued on August 2, 2007 and October 2, 2007, the MPSC also rejected the MPSC staff’s recommendations regarding $8 million of the remaining gas cost disallowance.  In a filing made with the MPSC on November 2, 2007, the MPSC staff withdrew from consideration the remaining $4.4 million in disallowance recommendations.  The Company expects the MPSC to accept the withdrawal of these recommendations by the end of 2007.

25

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

New England Gas Company.  On June 8, 2007, New England Gas Company filed with the Massachusetts Department of Public Utilities (MDPU) a proposed rate settlement with respect to its Massachusetts operations. The settlement agreement provides, among other things, for an overall revenue increase of $4.6 million phased in over an eight-month period, including the implementation of adjustment mechanisms for the recovery of pension costs, other postretirement benefit costs and gas cost-related uncollectible expense effective August 1, 2007, and a base rate increase of $2 million on April 1, 2008.  The MDPU issued an order on July 31, 2007 approving the rate settlement agreement effective August 1, 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 September 30, 2007 and December 31, 2006 to cover probable environmental response actions:

	September 30,		December 31,
	2007		2006
	(In thousands)
Current	$	5,997	$	5,098
Noncurrent		15,859		18,632
Total Environmental Liabilities	$	21,856	$	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 for contamination resulting from the past use of lubricants containing polychlorinated biphenyls (PCBs) in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle has developed and is implementing a program to remediate such contamination. Remediation and decontamination has been completed at each of the 35 compressor station sites where auxiliary buildings that house the air compressor equipment were impacted by the past use of lubricants containing PCBs. At some locations, PCBs have been identified in paint that was applied many years ago. A program has been implemented to remove and dispose of PCB impacted paint during painting activities. At one location on the Trunkline system, PCBs were discovered on the painted

26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

surfaces of equipment in a building that is outside of the scope of the compressed air system program and the existing PCB impacted paint program.  The estimated cost to remediate the painted surfaces at this location is approximately $300,000.  An initial assessment program was undertaken to determine whether this condition exists at any of the other 78 similar buildings on the PEPL and Trunkline systems.  At the seven locations assessed, which comprised a total of 15 buildings, preliminary analysis identified PCBs at regulated levels in a small number of samples at two locations.  An expanded assessment program is being developed.  Until the results of the expanded 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 as of that 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.

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. The rule, with which Panhandle is in compliance and which had a final implementation date of May

27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2007, affected 20 large internal combustion engines on Panhandle’s system in Illinois and Indiana with an approximate cost of $23 million for capital improvements which has been incurred as of September 30, 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.  As originally proposed, the Illinois rule required controls on engines regulated under the U.S. EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2011.  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, which was the primary driver of costs to PEPL and Trunkline.  The pipeline consortium specifically objected to treatment of the statewide applicability issue under an Illinois “Fast Track” rulemaking process.  In early May, the pipeline consortium filed for a preliminary injunction in state court challenging the application of the Fast Track process.  On May 17, 2007, the IPCB ruled in favor of the pipeline consortium by bifurcating the statewide applicability provision from the rest of the proposed rule.  On September 20, 2007 the IPCB approved the rule that applies to the engines regulated under the NOx SIP Call rule, which the pipeline consortium was not contesting. Due to delayed approval of the rule, the compliance deadline was changed from May 1, 2007 to January 1, 2008.  On August 23, 2007, the IEPA filed a motion to cancel hearings and pre-filing deadlines for the bifurcated statewide portion of the proposed Illinois engine rule, which was later granted. The IEPA conducted an industry meeting on October 4, 2007 and introduced a new proposal to withdraw the statewide applicability provisions of the current proposed rule and apply the rule requirements to non-attainment areas. No controls on PEPL and Trunkline stations would be required under the most recent proposal. However, the IEPA indicated it was reserving the right to make future proposals for statewide controls.  In the event the IEPA moves forward with the rule as originally proposed, preliminary estimates indicate the cost of compliance would require minimum capital expenditures of approximately $45 million for emission controls.

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 required the installation of emission controls. 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 East Texas locations.  Approximately $16.7 million of the $17.6 million of capital expenditures have been incurred as of September 30, 2007.  Permit limits were placed on grandfathered engines at two facilities in West Texas that are owned by PEPL.  An estimated $1.5 million in capital expenditures will be required to comply with permit limitations for the West Texas facilities.

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.  The rule, with which PEPL and Trunkline are in compliance and which had a final implementation date of June 2007, seeks to reduce formaldehyde emissions by 76 percent from these engines by requiring use of catalytic controls.  PEPL has one engine fully regulated under this rule.  For the other PEPL and Trunkline engines potentially subject to the engine MACT rule, emission controls and operating restrictions have been used to lower emissions below MACT thresholds.  Compliance with these regulations necessitated an estimated expenditure of $1.2 million for capital improvements.

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.

28

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, resulting primarily from releases of hydrocarbons.  Southern Union Gas Services has a program to remediate such contamination.  The remediation typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity.  The ultimate liability and total costs associated with these sites will depend upon many factors. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Air Quality Control. On June 16, 2006, Southern Union Gas Services, as the facility operator and holder of a 50 percent interest in the Grey Ranch facility, submitted information to the TCEQ in connection with a request to permit its Grey Ranch, Texas facility to continue its current level of emissions.  The State of Texas requires all previously grandfathered emission sources to obtain permits or shut down by March 1, 2008.  By letter dated September 5, 2007, the TCEQ issued a permit extending current emission levels to March 1, 2009.  At the conclusion of the extension period, Southern Union Gas Services must implement an emission control strategy that achieves specific maximum allowable emissions rates.  At this time, it is anticipated that the Company will not bear any of the costs associated with an emissions control strategy.

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 of former MGPs that produced a fuel known as “town gas”. Some byproducts of the historic manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these byproducts are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required.  The sites include properties that are part of the Company’s ongoing operations, sites formerly owned or used by the Company and sites owned by third parties. Remediation typically involves the management of contaminated soils and may involve removal of old MGP structures and remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements, complexity and sharing of responsibility; some contamination may be unrelated to former MGPs. The ultimate liability and total costs associated with these sites will depend upon many factors. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, the Company could potentially be held responsible for contamination caused by other parties.  In some instances, the Company may share liability associated with contamination with other PRPs, and may also benefit from insurance policies or contractual indemnities that cover some or all of the cleanup costs. These sites are generally managed in the normal course of business or operations. The Company believes the outcome of these matters will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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

29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

engineered barrier, construction of which is anticipated in 2008.  Assessment activities continue both on- and off-site to define the nature and extent of the impacts.  It is estimated that the Company will spend approximately $8.6 million over the next several years to complete the investigation and remediation activities at this site, as well as maintain the engineered barrier.  As New England Gas Company is allowed to recover environmental remediation expenditures through rates associated with its Massachusetts operations, the estimated costs associated with this site have been included in Regulatory Assets in the Condensed Consolidated Balance Sheet.

Litigation

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts.  Where appropriate, the Company has made accruals in accordance with FASB Statement No. 5, Accounting for Contingencies, in order to provide for such matters.  The Company believes the final disposition of these proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Bay Street, Tiverton, Rhode Island Site.  On March 17, 2003, the Rhode Island Department of Environmental Management (RIDEM) sent the Company’s New England Gas Company division a letter of responsibility pertaining to soils allegedly impacted by historic MGP residuals in a residential neighborhood in Tiverton, Rhode Island. Without admitting responsibility or accepting liability, New England Gas Company began assessment work in June 2003 and has continued to perform assessment field work since that time. On September 19, 2006, RIDEM filed an Amended Notice of Violation seeking an administrative penalty of $1,000/day, which as of the date of RIDEM’s filing totaled $258,000 and continues to accrue.  In June 2007, the Rhode Island Legislature considered, but failed to adopt, legislation that would have increased the maximum administrative penalty under a Notice of Violation to $50,000/day on a prospective basis.  In that RIDEM administrative proceeding, the Case Management Order calls for the completion of discovery by November 15, 2007.  RIDEM has filed a motion to amend the Case Management Order which, if adopted, will extend the discovery period through April 2008.  On April 19, 2007, the Company filed a complaint, and an accompanying preliminary injunction motion, against RIDEM in Rhode Island Superior Court, seeking, among other things, a declaratory judgment that RIDEM's Amended Notice of Violation is premised on an unlawful application of RIDEM's regulations and that RIDEM's pending administrative proceeding against the Company is invalid.  On July 13, 2007, the Superior Court dismissed the Company’s suit, finding that RIDEM’s Administrative Adjudication Division (AAD) has original jurisdiction to determine “responsible party” status and finding premature the Company’s challenge to RIDEM’s unlawful application of its own regulations because the Company did not first seek a ruling on that issue from RIDEM’s AAD.  The Company has appealed from part of the Superior Court’s ruling, and has also filed a motion for summary judgment in the AAD proceeding seeking dismissal of same based on RIDEM’s unlawful application of its own regulations.

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’s latest scheduling order sets a deadline for completion of discovery by February 29, 2008.  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.  On September 11, 2007, the Court granted the Company’s motion to serve third-party complaints on eight PRPs, all of which have now been served in the action.  On October 24, 2007, the Court granted the Company’s unopposed motion to join a ninth PRP as a third-party defendant.  Plaintiffs have moved to sever the third-party complaints from the main action, which motion is not fully briefed nor yet scheduled for argument.  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

30

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Mercury Release.  In October 2004, New England Gas Company discovered that one of its facilities had been broken into and that mercury had been released both inside a building and in the immediate vicinity, including a parking lot in a neighborhood several blocks away. Mercury from the parking lot was apparently tracked into nearby apartment units, as well as other buildings. Cleanup was completed at the property and nearby apartment units. The vandals who broke into the facility were arrested and convicted. On October 16, 2007, the U.S. Attorney in Rhode Island filed a three-count indictment against the Company in the U.S. District Court for the District of Rhode Island alleging violation of permitting requirements under the federal Resource Conservation and Recovery Act and notification requirements under the federal Emergency Planning and Community Right to Know Act relating to the 2004 incident.  The Company entered a not guilty plea on October 29, 2007 and will vigorously defend itself in such action.  The Company believes the outcome of this matter will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On January 20, 2006, a complaint was filed against the Company in the Superior Court in Providence, Rhode Island regarding the mercury release from the Pawtucket facility, asserting claims by certain Pawtucket residents for personal injury and property damage as a result of the release.  The suit was removed to Rhode Island federal court on January 27, 2006. A motion to remand the case to state court filed by plaintiffs was denied on April 16, 2007.  The Company thereafter moved to dismiss plaintiffs’ amended complaint, which motion was granted in part, dismissing claims for public nuisance, private nuisance and violation of Rhode Island’s Hazardous Waste Management Act, leaving plaintiffs with claims for negligence and strict liability.  The Company will continue to vigorously defend the suit.  On October 18, 2007, an attorney representing other Pawtucket residents filed suit against the Company in the Superior Court in Providence asserting claims similar to those pending in the above-described federal court suit for personal injury and property damage.  The Company will vigorously defend such suit.  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) claimed trespass and unjust enrichment in respect of the storage rights to property that contains a portion of the Company’s Howell storage field.  The Company filed an action for condemnation to obtain the storage rights from Hope Land.  Trial before the Michigan Circuit Court 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 and no recovery in respect of unjust enrichment.  Following the verdict, the matter was settled and an Order of Dismissal was entered in the Court on July 3, 2007.  The settlement of this matter had no material impact on the Company’s consolidated financial position, results of operations or cash flows.

Jack Grynberg.  Jack Grynberg, an individual, filed actions for damages against a number of companies, including Panhandle, now transferred to the U.S. District Court for the District of Wyoming, alleging mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  Among the defendants are Panhandle, Citrus, Florida Gas and certain of their affiliates (Company Defendants).  On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against the Company Defendants.  Grynberg is appealing that action to the Tenth Circuit Court of Appeals.  Grynberg’s opening brief was filed on July 31, 2007.  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.

31

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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.  Following appeal to the Ninth Circuit Court of Appeals and remand to the District Court, 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 appealed to the Ninth Circuit Court of Appeals.  The Company anticipates that the Court’s opinion will be issued in early 2008.  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 Damage.  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 September 30, 2007, the Company has incurred approximately $34.9 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 delays are not eligible for insurance recovery.  As of September 30, 2007, the Company has received payments of $7.6 million from its insurance carriers.  No receivables due from the insurance carriers have been recorded as of September 30, 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 million, $2.8 million of which had been incurred as of September 30, 2007.  The Company will seek recovery of these expense and capital amounts as part of the hurricane-related claims.

32

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

15. Reportable Segments

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

The Transportation and Storage segment operations are conducted through Panhandle and the 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.  In August 2006, the Company completed the sales of the assets of both its PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.  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- and nine-month periods ended September 30, 2007 and 2006.

33

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table sets forth certain selected financial information for the Company’s segments for the three- and nine-month periods ended September 30, 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.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Segment Data	2007			2006			2007			2006
	(In thousands)						(In thousands)
Revenues from external customers:
Transportation and Storage	$	158,963		$	143,397		$	489,699		$	422,149
Gathering and Processing		285,182			347,386			887,111			779,711
Distribution		80,093			72,365			513,864			458,886
Total segment operating revenues		524,238			563,148			1,890,674			1,660,746
Corporate and other		1,235			1,270			3,080			3,193
	$	525,473		$	564,418		$	1,893,754		$	1,663,939
Depreciation and amortization:
Transportation and Storage	$	21,863		$	18,364		$	63,634		$	52,823
Gathering and Processing		14,713			13,932			43,849			32,884
Distribution		7,633			7,514			22,646			22,889
Total segment depreciation and amortization		44,209			39,810			130,129			108,596
Corporate and other		691			469			1,901			1,204
	$	44,900		$	40,279		$	132,030		$	109,800
Earnings (loss) from unconsolidated investments:
Transportation and Storage	$	24,300		$	19,382		$	80,822		$	46,769
Gathering and Processing		263			(309	)		947			(309	)
Corporate and other		257			184			217			196
	$	24,820		$	19,257		$	81,986		$	46,656
Other income (expense), net:
Transportation and Storage	$	66		$	(178	)	$	1,133		$	3,116
Gathering and Processing		543			335			1,519			1,519
Distribution		(336	)		(1,086	)		(1,140	)		(3,221	)
Total segment other income (expense), net		273			(929	)		1,512			1,414
Corporate and other		(2,234	)		119			288			36,419
	$	(1,961	)	$	(810	)	$	1,800		$	37,833
Segment performance:
Transportation and Storage EBIT	$	90,129		$	85,990		$	300,906		$	248,802
Gathering and Processing EBIT		20,020			17,001			41,506			42,031
Distribution EBIT		9,173			(4,865	)		49,162			18,748
Total segment EBIT		119,322			98,126			391,574			309,581
Corporate and other		517			(9,718	)		6,186			17,508
Interest expense		50,703			56,929			154,034			162,128
Federal and state income tax expense		23,853			19,650			68,747			63,392
Earnings from continuing operations		45,283			11,829			174,979			101,569
Earnings (loss) from discontinued operations before
income taxes		-			(27,438	)		-			6,111
Federal and state income tax expense		-			147,035			-			158,642
Loss from discontinued operations		-			(174,473	)		-			(152,531	)
Net earnings (loss)		45,283			(162,644	)		174,979			(50,962	)
Preferred stock dividends		4,342			4,341			13,024			13,023
Net earnings (loss) available for common stockholders	$	40,941		$	(166,985	)	$	161,955		$	(63,985	)

34

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	September 30,		December 31,
Segment Data	2007		2006
	(In thousands)
Total assets:
Transportation and Storage	$	4,258,744	$	3,874,318
Gathering and Processing		1,663,841		1,722,055
Distribution		997,850		1,016,491
Total segment assets		6,920,435		6,612,864
Corporate and other		128,303		169,926
Total consolidated assets	$	7,048,738	$	6,782,790

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(In thousands)				(In thousands)
Expenditures for long-lived assets:
Transportation and Storage	$	181,771	$	71,207	$	379,070	$	147,940
Gathering and Processing		9,560		11,196		33,377		27,991
Distribution		11,501		12,570		30,240		35,421
Total segment expenditures for
long-lived assets		202,832		94,973		442,687		211,352
Corporate and other		841		1,172		2,394		2,284
Total consolidated expenditures for
long-lived assets	$	203,673	$	96,145	$	445,081	$	213,636

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, which were paid in the first quarter of 2007.  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, which were paid in the first quarter of 2007.

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.

35

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			Nine Months Ended
	September 30, 2006			September 30, 2006
	(In thousands, except per share amounts)
Operating revenues	$	41,891		$	512,935
Operating income		2,108			57,079
Loss from discontinued operations (1)		(174,473	)		(152,531	)
Net loss available from discontinued operations per share:
Basic	$	(1.50	)	$	(1.35	)
Diluted	$	(1.48	)	$	(1.31	)

__________________

(1)  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 the Sid Richardson Energy Services business 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 the Sid Richardson Energy Services business 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.

	Nine Months Ended
	September 30, 2006
	(In thousands, except per share amounts)
Operating revenue	$	1,894,488
Net earnings available for common shareholders
from continuing operations		103,562
Net earnings available for common shareholders from continuing
operations per share:
Basic	$	0.92
Diluted	$	0.89

18. Subsequent Event

On October 26, 2007, PEPL issued $300 million in senior notes due November 1, 2017 with an interest rate of 6.20 percent (6.20% Senior Notes).  In connection with the issuance of the 6.20% Senior Notes, the Company incurred underwriting and discount costs of approximately $2.7 million.  The debt was priced to the public at 99.741 percent, resulting in $297.3 million in proceeds to the Company.  The proceeds were initially loaned from PEPL to the Company and were used to repay approximately $246 million outstanding under the credit facilities. 

The remaining proceeds of $51.3 million were initially invested by the Company and subsequently utilized to fund working capital obligations.  The Company will repay the funds to PEPL, as needed, to fund ongoing capital programs as discussed more fully in Note 13 – Regulation and Rates.

36

ITEM 2.                        MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operations is provided as a supplement to the accompanying unaudited interim condensed consolidated financial statements and notes to help provide an understanding of Southern Union’s financial condition, changes in financial condition and results of operations.  The following section includes an overview of the Company’s business as well as recent developments that the Company believes are important in understanding its results of operations, and to anticipate future trends in those operations.  Subsequent sections include an analysis of the Company’s results of operations on a consolidated basis and on a segment basis for each reportable segment, and information relating to the Company’s liquidity and capital resources, quantitative and qualitative disclosures about market risk and other matters.

OVERVIEW

The Company’s business purpose is to provide gathering, processing, transportation, storage and distribution of natural gas and natural gas liquids in a safe, efficient and dependable manner.  The Company’s reportable business segments are determined based on the way internal managerial reporting presents the results of the Company’s various businesses to its executive management for use in determining the performance of the businesses and in allocating resources to the businesses as well as based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment.  The Company operates in three reportable segments:  Transportation and Storage, Gathering and Processing, and Distribution.

RESULTS OF OPERATIONS

Overview

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

· items that do not impact net earnings 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.

37

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007		2006
	(In thousands)					(In thousands)
EBIT:
Transportation and storage segment	$	90,129	$	85,990		$	300,906	$	248,802
Gathering and processing segment		20,020		17,001			41,506		42,031
Distribution segment		9,173		(4,865	)		49,162		18,748
Corporate and other		517		(9,718	)		6,186		17,508
Total EBIT		119,839		88,408			397,760		327,089
Interest		50,703		56,929			154,034		162,128
Earnings from continuing operations before
income taxes		69,136		31,479			243,726		164,961
Federal and state income taxes		23,853		19,650			68,747		63,392
Earnings from continuing operations		45,283		11,829			174,979		101,569
Discontinued operations:
Earnings (loss) from discontinued operations
before income taxes		-		(27,438	)		-		6,111
Federal and state income taxes		-		147,035			-		158,642
Loss from discontinued operations		-		(174,473	)		-		(152,531	)
Preferred stock dividends		4,342		4,341			13,024		13,023
Net earnings (loss) available for common stockholders	$	40,941	$	(166,985	)	$	161,955	$	(63,985	)

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.  The Company’s $207.9 million increase in Net earnings available for common stockholders was primarily due to:

· Impact of the $174.5 million loss from discontinued operations in the 2006 period associated with the August 2006 sales of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division;

· Higher EBIT contribution of $14 million from the Distribution segment primarily due to higher net operating revenue resulting from the Missouri Gas Energy rate increase, effective April 3, 2007, eliminating the impact of weather and conservation for residential margin revenue;

· Higher EBIT of $10.2 million from corporate and other primarily due to the impact of $12.8 million of executive compensation awarded by the compensation committee of the Company’s Board of Directors in 2006 in respect of transactional activity;

· Lower interest expense of $6.2 million primarily due to the retirement of debt in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, partially offset by increased interest expense related to the $600 million Junior Subordinated Notes issued in October 2006 and higher interest expense on Panhandle debt primarily due to higher debt balances; and

· Higher EBIT contribution of $4.1 million from the Transportation and Storage segment largely due to higher equity earnings from Citrus resulting from the increase in the Company’s equity ownership in Citrus from 25 percent to 50 percent effective December 1, 2006.

These earnings improvements were partially offset by higher income tax expense from continuing operations of $4.2 million primarily due to $37.7 million of higher pre-tax earnings from continuing operations.  The impact of the higher tax expense was mitigated by the lower EITR of 35 percent in the 2007 period versus 62 percent in the 2006 period 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.

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Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.  The Company’s $225.9 million increase in Net earnings available for common stockholders was primarily due to:

· Impact of the $152.5 million loss from discontinued operations in the 2006 period associated with the August 2006 sales of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division;

· Higher EBIT contributions of $52.1 million from the Transportation and Storage segment largely due to higher LNG terminalling revenue associated with the Trunkline LNG Phase I and Phase II expansions completed in April 2006 and July 2006, respectively, higher pipeline reservation revenues driven by higher average rates on contracts, higher parking revenues and higher equity earnings from Citrus resulting from the Company’s increased equity ownership in Citrus from 25 percent to 50 percent effective December 1, 2006;

· Higher EBIT contributions of $30.4 million from the Distribution segment primarily due to higher net operating revenue resulting from the Missouri Gas Energy rate increase effective April 3, 2007 eliminating the impact of weather and conservation for residential margin revenues; and

· Lower interest expense of $8.1 million primarily due to the retirement of debt in 2006 associated with the bridge loan facility entered into to finance the acquisition of the Sid Richardson Energy Services business, partially offset by increased interest expense related to the $600 million Junior Subordinated Notes issued in October 2006 and higher interest expense on Panhandle debt primarily due to higher debt balances.

These earnings improvements were partially offset by:

· 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 the Sid Richardson Energy Services business; and

· Higher income tax expense from continuing operations of $5.4 million primarily due to $78.8 million of higher pre-tax earnings from continuing operations.  The impact of the higher tax expense was mitigated by the lower EITR of 28 percent in the 2007 period versus 38 percent in the 2006 period 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.

Business Segment Results

Transportation and Storage Segment.  The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and from the Gulf Coast to Florida, and LNG terminalling and regasification services.Prior to the closing on December 1, 2006 of the transactions under the definitive redemption agreement between Energy Transfer and CCE Holdings (Redemption Agreement), resulting in the Company transferring its interest in Transwestern in exchange for Energy Transfer’s interest in CCE Holdings, 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 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.  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.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Transportation and Storage Segment	2007		2006			2007		2006
	(In thousands)					(In thousands)
Operating revenues	$	158,963	$	143,397		$	489,699	$	422,149
Operating expenses		63,987		51,920			184,676		149,340
Depreciation and amortization		21,863		18,364			63,634		52,823
Taxes other than on income
and revenues		7,350		6,327			22,438		21,069
Total operating income		65,763		66,786			218,951		198,917
Earnings from unconsolidated
investments		24,300		19,382			80,822		46,769
Other income, net		66		(178	)		1,133		3,116
EBIT	$	90,129	$	85,990		$	300,906	$	248,802
Operating information:
Panhandle natural gas volumes transported
(in trillion British thermal units (TBtu))		341		271			1,116		861
CCE Holdings natural gas volumes transported (TBtu) (1)
Florida Gas		225		211			563		573
Transwestern		-		164			-		464

________________

(1) Represents 100 percent of Florida Gas and Transwestern natural gas volume transports versus the Company’s effective equity ownership interest.  The Company’s effective equity interests in Florida Gas and Transwestern were 25 percent and 50 percent, respectively, until December 1, 2006, when the Company’s interest in Transwestern was redeemed by Energy Transfer, increasing the Company’s effective interest in Florida Gas to 50 percent.

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.  The $4.1 million EBIT improvement in the three-month period ended September 30, 2007 versus the same period in 2006 was primarily due to higher equity earnings from unconsolidated investments of $4.9 million, now primarily consisting of the Company’s investment in Citrus, partially offset by a $779,000 EBIT reduction for Panhandle.

Panhandle’s $779,000 EBIT reduction was primarily related to the following items:

· Higher operating revenues of $15.6 million as the result of:

· Increased transportation and storage revenue of $16.2 million attributable to:

· Higher transportation reservation revenues of $7.1 million primarily due to reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand and utilization of contract capacity;

· Higher parking revenues of $5.8 million resulting from customer demand for parking services and market conditions;

· Higher storage revenues of $1.7 million due to increased contracted capacity; and

· Higher commodity revenues of $1.6 million due to higher throughput volumes including transportation of higher LNG volumes on Trunkline, higher volumes on Sea Robin due to adverse hurricane impacts on 2006 throughput, and higher throughput on Panhandle due to storage refill activity.

· A $1.7 million increase in LNG terminalling revenue based on higher volumes resulting from an increase in LNG cargoes; and

· A decrease in other revenue of $2.4 million primarily due to higher operational sales of gas in 2006.

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This improvement was offset by:

· Higher operating expenses of $12.1 million as the result of:

· A $4.2 million increase in contract storage costs attributable to an increase in leased capacity;

· A $2.9 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units;

· A $1.3 million increase in fuel tracker costs based on a net under-recovery in 2007;

· A $1.3 million increase in LNG power costs resulting from increased cargoes; and

· A $1.2 million net increase in labor and benefits.

· Increased depreciation and amortization expense of $3.5 million due to an increase in property, plant and equipment placed in service.  Depreciation and amortization expense is expected to continue to increase primarily due to higher capital spending, including compression modernization and other expenditures.

Equity earnings were higher by $4.9 million in 2007 versus 2006 primarily due to higher equity earnings of approximately $13.9 million from Citrus’ core business largely due to the increase in the Company’s effective ownership from 25 percent to 50 percent as a result of the transactions under the Redemption Agreement, which closed in December 2006. The higher equity earnings in 2007 versus 2006 were partially offset by the $9.1 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.

Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.  The $52.1 million EBIT improvement in the nine-month period ended September 30, 2007 versus the same period in 2006 was primarily due to improved contributions from Panhandle totaling $18 million and higher equity earnings from unconsolidated investments of $34.1 million, now primarily consisting of the Company’s investment in Citrus.

Panhandle’s $18 million EBIT improvement was primarily related to the following items:

· Higher operating revenues of $67.6 million as the result of:

· Increased transportation and storage revenue of $47.5 million primarily attributable to:

· Higher transportation reservation revenues of $22.1 million primarily due to reduced discounting resulting in higher average rates realized on contracts driven by higher customer demand and utilization of contract capacity and increased capacity sold;

· Higher parking revenues of $14 million resulting from customer demand for parking services and market conditions;

· Higher commodity revenues of $5.7 million due to higher throughput volumes including transportation of higher LNG volumes on Trunkline, higher volumes on Sea Robin due to adverse hurricane impacts on 2006 throughput, and higher throughput on Panhandle due to higher utilization driven by weather and storage refill activity; and

· Higher storage revenues of $5.7 million due to increased contracted capacity.

· A $25.3 million increase in LNG terminalling revenue based on 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

· A decrease in other revenue of $5.3 million primarily due to higher operational sales of gas in 2006.

This improvement was offset by:

· Higher operating expenses of $35.3 million as the result of:

· A $10.1 million increase in corporate services costs relating to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services costs to the remaining business units and an increase in management and royalty fees due to higher revenues;

· An $8.9 million increase in contract storage costs primarily due to an increase in leased capacity;

· A $7.7 million increase in LNG power costs resulting from increased cargoes;

· A $2.6 million increase in labor and benefits;

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· A $3.7 million increase in fuel tracker costs based on a net under-recovery in 2007;

· A $1.1 million increase in insurance expense due to higher premiums; and

· A $1 million increase in legal costs.

· Increased depreciation and amortization expense of $10.8 million due to an increase in property, plant and equipment placed in service, including the Trunkline LNG Phase I and Phase II expansions.

Equity earnings were higher by $34.1 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 $35.4 million from Citrus’ core business largely due to the increase in the Company’s effective ownership from 25 percent to 50 percent as a result of the transactions under the Redemption Agreement, which closed in December 2006;

· A $7.6 million gain related to a reduction in a previously established liability to Enron associated with the Duke lawsuit;

· A gain of $7.5 million recognized by Citrus associated with settlement of the Duke lawsuit; and

· A $3.6 million gain related to the sale of Enron bankruptcy claim receivables.

The higher equity earnings in 2007 versus 2006 were partially offset by the $20.1 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 Ended					Nine Months Ended
	September 30,					September 30,
Gathering and Processing Segment	2007		2006			2007		2006 (1)
	(In thousands)					(In thousands)
Gross margin (2)	$	54,887	$	49,282		$	143,851	$	116,380
Operating expenses		20,240		17,689			58,763		41,030
Depreciation and amortization		14,713		13,932			43,849		32,884
Taxes other than on income and revenues		720		686			2,199		1,645
Total operating income		19,214		16,975			39,040		40,821
Earnings (loss) from unconsolidated
investments		263		(309	)		947		(309	)
Other income, net		543		335			1,519		1,519
EBIT	$	20,020	$	17,001		$	41,506	$	42,031
Operating information:
Volumes:
Average natural gas processed volumes (MMbtu/day)		422,095		448,296			427,710		453,847
Average liquids processed volumes (gallons/day)		1,299,267		1,435,890			1,328,688		1,443,317
Average natural gas wellhead volumes (MMbtu/day)		664,960		589,425			634,075		576,674
Prices:
Average WAHA natural gas daily price ($/MMbtu)	$	5.72	$	5.70		$	6.39	$	5.72
Average natural gas liquids daily price ($/gallon)		1.13		1.02			1.00		0.97
Average plant processing spread ($/gallon)		0.62		0.52			0.45		0.46

________________

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

(2) Gross margin consists of operating revenues less cost of products sold.  The Company believes that this measurement is

more meaningful for understanding and analyzing the Gathering and Processing segment’s operating results for the periods

presented because commodity costs are a significant factor in the determination of the segment’s revenues.  See PART I, ITEM 1. Financial Statement (Unaudited), Note 7 –Unconsolidated Investments for additional related information.

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.  The $3 million EBIT improvement in the three-month period ended September 30, 2007 versus the same period in 2006 was primarily due to the following items:

· Higher average commodity-driven processing spreads of $0.62 in the 2007 period versus $0.52 for the 2006 period, partially offset by lower volumes processed;

· A decrease in fuel, flare and unaccounted for gas losses by an average of 990 MMBtu per day, resulting in an increase of approximately $500,000; and

· Increased earnings of $337,000 related to put option hedges.

These EBIT increases were offset by the following items:

· Higher operating expenses experienced in the mid-stream energy industry primarily resulting from increased competition for personnel, equipment and materials, placing upward pressure on prices for labor, employee benefits and materials such as chemicals and lubricants affected by higher crude oil costs; and

· Increased depreciation expense of $781,000 due to the increased placement of assets into service in the 2007 period versus the 2006 period.

See PART I, ITEM 1. Financial Statement (Unaudited), Note 9 – Derivative Instruments and Hedging Activities – Gathering and Processing Segment for additional related information.

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Nine-month period ended September 30, 2007 versus the seven-month period ended September 30, 2006.  The $525,000 EBIT reduction for the nine-month period ended September 30, 2007 versus the post-acquisition seven-month period ended September 30, 2006 was primarily due to the following items:

· Gross margin was higher by $27.5 million primarily due to the realization of operating results for the complete nine-month period in 2007 versus only seven months in the 2006 period, the favorable impact of higher average WAHA natural gas prices of $6.39 in the 2007 period versus $5.72 in the 2006 period offset by the impact of approximately $10.6 million of unusually high levels of fuel, flare and unaccounted for gas losses primarily attributable to capacity and treating limitations experienced during the second quarter of 2007 at the Jal Plant treating facility; and

· Operating expenses and depreciation and amortization expense were higher by $17.7 million and $11 million, respectively, primarily due to the incurrence of nine months of activity in the 2007 period versus seven months in the 2006 period and general cost increases experienced in the mid-stream energy industry.  Operating expenses were also impacted by a $4.2 million increase in corporate services costs due to Southern Union’s disposition of certain assets during 2006, resulting in a larger allocation of corporate services 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 87 percent of its total customers and approximately 69 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.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Distribution Segment	2007			2006			2007			2006
	(In thousands)
Net operating revenues   (1)	$	45,657		$	29,275		$	162,542		$	124,011
Operating expenses		26,693			23,270			81,649			71,568
Depreciation and amortization		7,633			7,514			22,646			22,889
Taxes other than on income
and revenues		1,822			2,270			7,945			7,585
Total operating income		9,509			(3,779	)		50,302			21,969
Other income (expenses), net		(336	)		(1,086	)		(1,140	)		(3,221	)
EBIT	$	9,173		$	(4,865	)	$	49,162		$	18,748

________________

(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 September 30, 2007 versus the three-month period ended September 30, 2006.  The $14 million EBIT improvement in the three-month period ended September 30, 2007 versus the same period in 2006 was primarily due to the following items:

· Net operating revenues increased $16.4 million primarily due to the Missouri Gas Energy $27.2 million annual revenue rate increase effective April 3, 2007.

· Operating expenses increased $3.4 million primarily due to:

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· Increased benefit costs of approximately $1.2 million primarily due to the recognition of higher pension costs recovered in rates associated with the recent Missouri Gas Energy rate case;

· Increased general expenses of approximately $917,000 primarily due to cathodic protection maintenance, the outsourcing of billing and call services and an increase of advertising expense;

· Increased labor expenses of approximately $585,000 primarily due to the filling of vacant positions and wage and merit increases in 2007 versus 2006; and

· Higher uncollectible accounts of approximately $449,000 resulting from higher revenues realized in the 2007 period versus the 2006 period.

Nine-month period ended September 30, 2007 versus the Nine-month period ended September 30, 2006.  The $30.4 million EBIT improvement in the nine-month period ended September 30, 2007 versus the same period in 2006 was primarily due to the following items:

· Net operating revenues increased $38.5 million primarily due to the Missouri Gas Energy $27.2 million annual revenue rate increase effective April 3, 2007 and higher consumption volumes resulting from colder weather in 2007 versus 2006.

· Operating expenses increased $10.1 million primarily due to:

· Increased benefit costs of approximately $3.1 million primarily due to the recognition of higher pension costs recovered in rates associated with the recent Missouri Gas Energy rate case;

· Increased labor expenses of approximately $2.4 million primarily due to the filling of vacant positions and wage and merit increases in 2007 versus 2006;

· Increased general expenses of approximately $2 million primarily due to cathodic protection maintenance, an increase in the weatherization program mandated by the rate case settlement, the outsourcing of billing and call services and the establishment of the Hot Water Rebate and Education Program;

· Higher uncollectible accounts of approximately $952,000 resulting from higher revenues realized in the 2007 period versus the 2006 period;

· Increased paid time off of $851,000 primarily due to higher time off with pay loading rates; and

· Increased legal fees of $729,000.

Corporate and Other

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.

The $10.2 million EBIT improvement for the three-month period ended September 30, 2007 versus the same period in 2006 was primarily due to the impact of $12.8 million of executive bonus compensation awarded by the compensation committee of the Company’s Board of Directors in 2006 in respect of transactional activity.

Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.  The $11.3 million EBIT reduction for the nine-month period ended September 30, 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 the Sid Richardson Energy Services business;

· A decrease in operating expenses of $25 million in 2007 versus 2006 due to executive bonus compensation of $12.8 million awarded by the compensation committee of the Company’s Board of Directors in 2006 in respect of transactional activity, a larger allocation of corporate services costs to the Company’s business units and an increase in management and royalty fees from Panhandle due to higher revenues;

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

· Impact of a $1 million charge to record a reserve in March 2006 for final estimated costs resulting from a sales and use tax audit.

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Interest Expense

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.  Interest expense was $6.2million lower in 2007 compared with 2006 primarily due to:

· Impact of higher interest expense of $17.6 million and higher debt issuance cost amortization of $2.6 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 using approximately $1.1 billion in net proceeds from the sale of certain assets in August 2006 and funds obtained in October 2006 from the issuance of the $600 million Junior Subordinated Notes;

· Lower interest expense of $648,000 associated with interest owed to MGE’s ratepayers in connection with its purchased gas cost recovery mechanism primarily due to higher levels of overcollections in 2006;

· Lower interest expense of $452,000 associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2007 compared to 2006;

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

· Increased interest expense of $4.2 million related to Panhandle debt primarily due to higher debt balances in 2007 versus 2006.

Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.  Interest expense was $8.1million lower in 2007 compared with 2006 primarily due to:

· Impact of interest expense of $47.3 million and debt issuance cost amortization of $7.8 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 using approximately $1.1 billion in net proceeds from the sale of certain assets in August 2006 and funds obtained in October 2006 from the issuance of the $600 million Junior Subordinated Notes;

· Lower interest expense of $5 million associated with borrowings under the Company’s credit agreements primarily due to lower average outstanding balances in 2007 compared to 2006;

· Lower interest expense of $2.1 million due to the retirement of the 2.75% Senior Notes in August 2006;

· Lower interest expense of $1.3 million associated with interest owed to MGE’s ratepayers in connection with its purchased gas cost recovery mechanism primarily due to higher levels of overcollections in 2006;

· Increased interest expense of $32.4 million related to the $600 million Junior Subordinated Notes issued in October 2006;

· Increased interest expense of $18.6 million related to Panhandle debt primarily due to higher debt balances in 2007 versus 2006; and

· Increased interest expense of $4.8 million under the 6.15% Senior Notes issued in August 2006.

Federal and State Income Taxes from Continuing Operations

Three-month period ended September 30, 2007 versus the three-month period ended September 30, 2006.

The EITR from continuing operations for the three-month periods ended September 30, 2007 and 2006 was 35 percent and 62 percent, respectively.The decrease in the EITR from continuing operations was primarily due to:

· Tax benefits 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 September 30, 2007 and 2006, the tax impact of the dividends received deduction was a benefit of $8.1 million and an expense of $166,000, respectively; and

· Additional tax expense resulting from nondeductible executive compensation. For the three-month periods ended September 30, 2007  and 2006, the additional tax expense resulting from nondeductible executive compensation was nil and $3.2 million, respectively.

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Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.

The EITR from continuing operations for the nine-month periods ended September 30, 2007 and 2006 was 28 percent and 38 percent, respectively. The decrease in the EITR from continuing operations was primarily due to:

· Tax benefits of $28.2 million in 2007 versus $4.9 million in 2006 associated with the increase in the dividends received deduction as a result of increased dividends from the Company’s unconsolidated investment in Citrus; and

· Additional tax expense resulting from nondeductible executive compensation. For the nine-month periods ended September 30, 2006, the additional tax expense resulting from nondeductible executive compensation was approximately $172,000 and $3 million, respectively.

Earnings from Discontinued Operations

Earnings (loss) from discontinued operations included in the 2006 periods are associated with the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division, which were sold in August 2006.  See PART I. Item 1. Financial Statements (Unaudited), Note 16 – Discontinued Operations for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Cash generated from internal operations constitutes the Company’s primary source of liquidity.  The Company’s $767.8 million working capital deficit at September 30, 2007 is expected to be funded by cash flows from operations and refinancings to be negotiated as more fully described in the Financing Activities discussion.  Additional sources of liquidity include use of available credit facilities and may include various equity offerings, project and bank financings, issuance of long-term debt and proceeds from asset dispositions.  The availability and terms relating to such liquidity will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure and conditions in the financial markets at the time of such offerings. Acquisitions, which generally require a substantial increase in expenditures, and related financings also affect the Company's combined results 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

Nine-month period ended September 30, 2007 versus the nine-month period ended September 30, 2006.  Cash flows provided by operating activities were $388.7 million for the nine-month period ended September 30, 2007 compared with cash flows provided by operating activities of $328.7 million for the same period in 2006.  Changes in operating assets and liabilities net of acquisitions provided cash of $2 million in 2007 and $65.7 million in 2006, resulting in a change in cash of $63.7 million in 2007 compared to 2006.  The $63.7 million decrease in cash is primarily due to lower receivables from the Distribution segment reduced by $159.3 million during the 2006 period versus $84.9 million in the 2007 period primarily due to higher receivables in December 2005 versus December 2006 resulting from the colder winter season.  The Company received $23.4 million less from cash settlements of put options in the 2007 period versus the 2006 period.  In the 2006 period, the Company’s discontinued operations provided cash of $26.3 million.  These changes, resulting in a higher usage of cash from operating assets and liabilities in the 2007 period versus the 2006 period, were offset by $32.1 million of lower inventory levels primarily due to withdrawals from storage to meet customer and operational obligations and $24.3 million of lower deferred gas purchase costs due to pricing variations.

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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 nine-month periods ended September 30, 2007 and 2006 were $418.3 million and $688.3 million, respectively.  The $270 million decrease in invested cash is primarily due to the $1.54 billion (net of $53.2 million cash received) acquisition of the Sid Richardson Energy Services business completed on March 1, 2006, offset by the effect of the $1.08 billion disposition in August 2006 of the assets of the Company’s PG Energy natural gas distribution division and the Rhode Island operations of its New England Gas Company natural gas distribution division.  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.

	Nine Months Ended
	September 30,
Property, Plant and Equipment Additions	2007		2006
	(In thousands)
Transportation and Storage Segment
LNG Terminal Expansions/Enhancements	$	84,570	$	46,416
Trunkline Field Zone Expansion		134,203		4,393
East End Enhancement		35,861		26,197
Compression Modernization		48,609		1,786
Other, primarily pipeline integrity, system
reliability, information technology, air
emission compliance		75,827		69,148
Total		379,070		147,940
Gathering and Processing Segment		33,377		27,991	(1)
Distribution Segment
Missouri Safety Program		7,544		9,745
Other, primarily system replacement
and expansion		22,696		25,676
Total		30,240		35,421
Corporate and other		2,394		2,284
Total  (2)	$	445,081	$	213,636

____________________

(1)  Reflects expenditures for the period subsequent to the March 1, 2006 acquisition of the Sid Richardson Energy

       Services business versus the nine-month period ended September 30, 2006.

(2)  Includes net capital accruals totaling $63million and $14.5 million for the nine-month periods ended

      September 30, 2007 and 2006, respectively.

The Company’s capital expenditure programs through 2007 are expected to be funded primarily by cash flows from operations and from financings more fully described in the Financing Activities section.  See PART I, ITEM 1.  Financial Statements (Unaudited), Note 13 – Regulation and Rates and Note 14 – 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.

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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 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

Cash flows provided by financing activities were $43.5million and $349.6 million for the nine-month periods ended September 30, 2007 and 2006, respectively.  Financing activity cash flow changes were primarily due to net debt retirements of $89.3million in 2007 versus net debt issuances of $275.8 million in 2006.

Retirement of Debt Obligations

The Company plans to refinance with new debt or bank financings the majority of its $525 million of debt maturing in 2008.  Alternatively, the Company may retire such debt with proceeds from one or a combination of the following sources: (i) cash flows from operating activities; (ii) borrowings under existing credit facilities; and (iii) new equity offering(s).  The Company believes, based on its investment grade credit ratings and general financial condition, successful historical access to capital markets, current economic and capital market conditions and market expectations regarding the Company’s future earnings and cash flows, that it will be able to refinance and/or retire these obligations under acceptable terms within the next year.  There can be no assurance, however, that the Company will be able to achieve acceptable terms in any negotiation of new debt or bank financings.  Moreover, there can be no assurance the Company will be successful in its implementation of these refinancing and/or retirement plans and the Company’s inability to do so would cause a material adverse effect on the Company’s financial condition and liquidity.

The Company’s $540.1 million of long-term debt due within the next twelve months includes $100 million due in February 2008 that will be remarketed in accordance with the terms of the February 11, 2005 5% Equity Units issuance, whereby the Company will issue between 3,500,309 and 4,375,387 shares of its common stock, resulting in the estimated receipt of approximately $99 million in proceeds, and remarket the $100 million debt.

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OTHER MATTERS

Master Limited Partnership

On November 9, 2007, the Company announced its intention to pursue an initial public offering of units representing limited partner interests of a master limited partnership ("MLP"), to be formed by the Company to hold a portion of the gathering and processing assets of its Southern Union Gas Services business. The Company currently expects that a registration statement for the initial public offering will be filed by early 2008 and that the offering will close as soon as practicable following the effectiveness of the registration statement.

This Quarterly Report on Form 10-Q shall not constitute an offer to sell or the solicitation of an offer to buy any securities. Any offers, solicitations of offers to buy, or any sales of securities will only be made in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.

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 $10 million for the various policies utilized by the Company.  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.

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 September 30, 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 nine 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.

In July 2007, the Company substantially completed the process of migrating Southern Union Gas Services to its enterprise-wide general ledger and financial reporting system, including subsystems.  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

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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 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.

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PART II.  OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

Southern Union is a party to or has property subject to litigation and other proceedings, including matters arising under provisions relating to the protection of the environment, as described in PART I, ITEM 1. Financial Statements (Unaudited), Note 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 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 87 percent of its total customers and approximately 69 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

N/A

ITEM 5.  OTHER INFORMATION

All information required to be reported on Form 8-K for the quarter ended September 30, 2007 was appropriately reported.

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ITEM 6.  EXHIBITS

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

2(a) Purchase 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 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.)

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

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10(b) 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(c) 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(d) Second Amendment to the Fourth Amended and Restated Revolving Credit Agreement dated September 29, 2005, 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 October 23, 2007, 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) First Amendment to the Southern Union Company Director’s Deferred Compensation Plan, effective April 1, 2007, filed herewith.

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

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

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10(p) 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(q) 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(r) 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(s) 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  November 9, 2007	By /s/ GEORGE E. ALDRICH
	George E. Aldrich                               Vice President and Controller                               (authorized officer and principal                                  accounting officer)

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EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

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

I, George L. Lindemann, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  November 9, 2007

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board, President and

Chief Executive Officer

(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

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

I, Richard N. Marshall, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  November 9, 2007

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

(principal financial officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Southern Union Company (the “Company”) for the quarter ended September 30, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George L. Lindemann, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ GEORGE L. LINDEMANN                                                                      

George L. Lindemann

Chairman of the Board, President and

Chief Executive Officer

November 9, 2007

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

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report on Form 10-Q of Southern Union Company (the “Company”) for the quarter ended September 30, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard N. Marshall, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RICHARD N. MARSHALL                                                                      

Richard N. Marshall

Senior Vice President and

Chief Financial Officer

November 9, 2007

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

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