10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

____________________________

FORM 10-Q

For the quarterly period ended

September 30, 2005

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.)
417 Lackawanna Avenue Scranton, Pennsylvania (Address of principal executive offices)	18503-2013 (Zip Code)

Registrant's telephone number, including area code: (570) 614-5000

One PEI Center, Second Floor Wilkes-Barre, Pennsylvania (Former address of principal executive offices) 18711 (Former Zip Code)

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
5.75% Corporate Units	New York Stock Exchange
5.00% Corporate Units	New York Stock Exchange

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

Yes ü No___

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes ü No___

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).

Yes   __No_ü

The number of shares of the registrant's Common Stock outstanding on October 28, 2005 was 111,422,143.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

September 30, 2005

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)
ITEM 1. Financial Statements (Unaudited):
Consolidated statement of operations - three and nine months ended September 30, 2005 and 2004.	2-3
Consolidated balance sheet - September 30, 2005 and December 31, 2004.	4-5
Consolidated statement of stockholders’ equity and comprehensive income -- nine months ended September 30, 2005.	6
Consolidated statement of cash flows - nine months ended September 30, 2005 and 2004.	7
Notes to consolidated financial statements.	8-31
ITEM 2. Management's Discussion and Analysis of Results of Operation and Financial Condition.	32-43
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.	43
ITEM 4. Controls and Procedures.	44
PART II. OTHER INFORMATION:
ITEM 1. Legal Proceedings.	45
ITEM 6. Exhibits.	45
SIGNATURES	46

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,
	2005			2004
	(thousands of dollars, except shares and per share amounts)
Operating revenues:
Gas distribution	$	137,000		$	124,021
Gas transportation and storage		115,945			109,264
Other		2,102			1,237
Total operating revenues		255,047			234,522
Cost of gas and other energy		(74,276	)		(65,492	)
Revenue-related taxes		(4,647	)		(4,435	)
Net operating revenues, excluding depreciation and amortization		176,124			164,595
Operating expenses:
Operating, maintenance and general		98,657			101,705
Depreciation and amortization		30,404			30,593
Taxes, other than on income and revenues		6,774			13,557
Total operating expenses		135,835			145,855
Operating income		40,289			18,740
Other income (expense):
Interest		(33,184	)		(30,618	)
Earnings from unconsolidated investments		22,172			42
Other, net		(1,457	)		381
Total other expenses, net		(12,469	)		(30,195	)
Earnings (loss) before income taxes (benefit)		27,820			(11,455	)
Federal and state income taxes (benefit)		8,230			(4,315	)
Net earnings (loss)		19,590			(7,140	)
Preferred stock dividends		(4,341	)		(4,341	)
Net earnings (loss) applicable to common shareholders	$	15,249		$	(11,481	)
Net earnings (loss) applicable to common shareholders per share:
Basic	$	.14		$	(.14	)
Diluted	$	.13		$	(.14	)
Weighted average shares outstanding:
Basic		111,032,451			84,183,300
Diluted		114,934,039			84,183,300

See accompanying notes.

2

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

	Nine Months Ended September 30,
	2005			2004
	(thousands of dollars, except shares and per share amounts)
Operating revenues:
Gas distribution	$	960,953		$	936,575
Gas transportation and storage		361,766			355,684
Other		5,049			3,630
Total operating revenues		1,327,768			1,295,889
Cost of gas and other energy		(634,033	)		(618,290	)
Revenue-related taxes		(33,604	)		(32,369	)
Net operating revenues, excluding depreciation and amortization		660,131			645,230
Operating expenses:
Operating, maintenance and general		306,523			311,548
Depreciation and amortization		93,668			86,317
Taxes, other than on income and revenues		32,993			42,554
Total operating expenses		433,184			440,419
Operating income		226,947			204,811
Other income (expense):
Interest		(100,185	)		(91,886	)
Earnings from unconsolidated investments		57,745			119
Other, net		(5,034	)		1,552
Total other expenses, net		(47,474	)		(90,215	)
Earnings before income taxes		179,473			114,596
Federal and state income taxes		52,012			42,426
Net earnings		127,461			72,170
Preferred stock dividends		(13,023	)		(13,023	)
Net earnings applicable to common shareholders	$	114,438		$	59,147
Net earnings applicable to common shareholders per share:
Basic	$	1.05		$	.72
Diluted	$	1.02		$	.71
Weighted average shares outstanding:
Basic		108,721,451			81,768,052
Diluted		112,569,608			83,184,563

See accompanying notes.

3

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	September 30,			December 31,
	2005			2004
ASSETS	(thousands of dollars)
Property, plant and equipment:
Plant in service	$	4,085,520		$	3,869,221
Construction work in progress		217,322			237,283
		4,302,842			4,106,504
Less accumulated depreciation and amortization		(862,796	)		(778,876	)
Net property, plant and equipment		3,440,046			3,327,628
Current assets:
Cash and cash equivalents		636			30,053
Accounts receivable, billed and unbilled, net		181,001			333,492
Federal and state taxes receivable		3,071			--
Inventories		292,353			267,136
Gas imbalances - receivable		75,732			36,122
Prepayments and other assets		43,386			45,705
Total current assets		596,179			712,508
Goodwill		640,547			640,547
Deferred charges		256,832			199,064
Unconsolidated investments		688,918			631,893
Other		51,740			56,649
Total assets	$	5,674,262		$	5,568,289

See accompanying notes.

4

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (Continued)

(Unaudited)

	September 30,			December 31,
	2005			2004
STOCKHOLDERS’ EQUITY AND LIABILITIES	(thousands of dollars)
Stockholders’ equity:
Common stock, $1 par value; authorized 200,000,000 shares; issued 111,579,280 and 90,762,650 shares, respectively	$	111,579		$	90,763
Preferred stock, no par value; authorized 6,000,000 shares; issued 920,000 shares		230,000			230,000
Premium on capital stock		1,666,728			1,204,590
Less treasury stock, 404,536 shares at cost		(12,870	)		(12,870	)
Less common stock held in trust: 935,819 and 1,198,034 shares, respectively		(16,317	)		(17,980	)
Deferred compensation plans		14,052			14,128
Accumulated other comprehensive loss		(58,008	)		(59,118	)
Retained earnings		28,067			48,044
Total stockholders’ equity		1,963,231			1,497,557
Long-term debt and capital lease obligations		2,049,300			2,070,353
Total capitalization		4,012,531			3,567,910
Current liabilities:
Long-term debt and capital lease obligations due within one year		126,648			89,650
Notes payable		273,000			699,000
Accounts payable and accrued liabilities		120,947			183,018
Federal, state and local taxes payable		35,577			33,946
Accrued interest		23,611			36,934
Customer deposits		15,419			13,156
Deferred gas purchases		104,312			3,709
Gas imbalances - payable		77,508			102,567
Other		166,545			151,856
Total current liabilities		943,567			1,313,836
Deferred credits		303,395			321,049
Accumulated deferred income taxes		414,769			365,494
Commitments and contingencies
Total stockholders’ equity and liabilities	$	5,674,262		$	5,568,289

See accompanying notes.

5

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Unaudited)

														Accumulated
											Common			Other						Total
	Common		Preferred		Premium			Treasury			Stock			Comprehen-						Stock-
	Stock,$1		Stock, No		on Capital			Stock, at			Held in			sive Income			Retained			holders’
	Par Value		Par Value		Stock			Cost			Trust			(Loss)			Earnings			Equity
	(thousands of dollars)
Balance December 31, 2004	$	90,763	$	230,000	$	1,204,590		$	(12,870	)	$	(3,852	)	$	(59,118	)	$	48,044		$	1,497,557
Comprehensive income:
Net earnings		--		--		--			--			--			--			127,461			127,461
Net unrealized gain on hedging activities, net of tax		--		--		--			--			--			1,110			--			1,110
Comprehensive income		--		--		--			--			--			--			--			128,571
Preferred stock dividends		--		--		--			--			--			--			(13,023	)		(13,023	)
Distribution of common stock held in trust		--		--		3,130			--			4,186			--			--			7,316
Issuance of common stock		14,913		--		316,859			--			--			--			--			331,772
Issuance costs of equity units		--		--		(2,622	)		--			--			--			--			(2,622	)
Restricted stock award		--		--		3,540			--			(3,540	)		--			--			--
Restricted stock amortization		--		--		--			--			941			--			--			941
Contract adjustment payment		--		--		(1,759	)		--			--			--			--			(1,759	)
5% stock dividend		5,294		--		129,121			--			--			--			(134,415	)		--
Stock option award		--		--		3,848			--			--			--			--			3,848
Exercise of stock options		609		--		10,021			--			--			--			--			10,630
Balance September 30, 2005	$	111,579	$	230,000	$	1,666,728		$	(12,870	)	$	(2,265	)	$	(58,008	)	$	28,067		$	1,963,231

The Company’s common stock is $1 par value. Therefore, the change in Common Stock, $1 Par Value is equivalent to the change in the number of shares of common stock issued.

See accompanying notes.

6

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2005			2004
	(thousands of dollars)
Cash flows provided by (used in) operating activities:
Net earnings	$	127,461		$	72,170
Adjustments to reconcile net earnings to net cash flows provided by operating activities:
Depreciation and amortization		93,668			86,317
Amortization of debt expense		3,882			3,821
Amortization of debt premium		(1,853	)		(8,148	)
Deferred income taxes		48,561			41,864
Provision for bad debts		22,105			22,791
Earnings from unconsolidated investments		(57,745	)		(119	)
Non-cash stock compensation		3,848			--
Other		(852	)		(623	)
Changes in operating assets and liabilities:
Accounts receivable, billed and unbilled		130,385			144,103
Gas imbalance receivable		736			10,381
Accounts payable		(59,257	)		(42,844	)
Gas imbalance payable		(207	)		(14,364	)
Accrued interest		(13,323	)		(13,081	)
Customer deposits		2,263			(820	)
Deferred gas purchase costs		39,158			13,933
Inventories		(60,111	)		(34,320	)
Deferred charges		(128	)		(5,987	)
Deferred credits		(18,324	)		15,166
Prepaids and other assets		4,950			(5,386	)
Taxes and other liabilities		(13,347	)		(9,342	)
Net cash flows provided by operating activities		251,870			275,512
Cash flows used in investing activities:
Additions to property, plant and equipment		(211,925	)		(192,303	)
Notes receivable		--			(1,869	)
Other		(325	)		387
Net cash flows used in investing activities		(212,250	)		(193,785	)
Cash flows used in financing activities:
Increase (decrease) in bank overdraft		5,975			(4,407	)
Issuance of common stock		331,772			86,563
Issuance of equity units		100,000			--
Issuance cost of equity units		(2,622	)		--
Issuance of long-term debt		255,626			200,000
Issuance cost of debt		(922	)		(4,871	)
Issuance costs of preferred stock		--			(177	)
Dividends paid on preferred stock		(13,023	)		(12,734	)
Repayment of debt and capital lease obligations		(335,561	)		(247,776	)
Net payments under revolving credit facilities		(426,000	)		(94,500	)
Proceeds from exercise of stock options		9,218			6,228
Other		6,500			(3,491	)
Net cash flows used in financing activities		(69,037	)		(75,165	)
Change in cash and cash equivalents		(29,417	)		6,562
Cash and cash equivalents at beginning of period		30,053			20,810
Cash and cash equivalents at end of period	$	636		$	27,372
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	120,085		$	116,476
Income taxes	$	334		$	18,596

See accompanying notes.

7

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

I. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying unaudited interim consolidated financial statements of Southern Union Company (Southern Union or the Company)have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the SEC) for quarterly reports on Form 10-Q. These statements do not include all of the information and note disclosures that are required in an annual report under generally accepted accounting principles, and should be read in conjunction with Southern Union’s financial statements and notes thereto for the six months ended December 31, 2004, included in Southern Union’s Transition Report on Form 10-K, as amended, filed with the SEC. The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and reflect adjustments (including both normal recurring as well as any non-recurring) that are, in the opinion of management, necessary for a fair statement of results for the interim period. Because of the seasonal nature of Southern Union’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. All dollar amounts in the tables herein, except per share amounts, are stated in thousands of U.S. dollars unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current period presentation.

Stock Based Compensation. Southern Union accounts for stock option grants using the intrinsic-value method in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees, and related authoritative interpretations. Under the intrinsic-value method, no compensation expense is recognized because the exercise price of Southern Union’s employee stock options is greater than or equal to the market price of the underlying stock on the date of grant.

The following table illustrates the effect on net earnings (loss) and net earnings (loss) applicable to common shareholders per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, as amended by FASB Statement No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, to stock-based employee compensation:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005		2004
Net earnings (loss), as reported	$	19,590	$	(7,140	)	$	127,461	$	72,170
Add stock-based compensation expense included in reported net earnings (loss), net of related taxes		2,394		--			2,394		--
Deduct total stock-based employee compensation expense determined under fair value based method for all awards, net of related taxes		2,736		671			3,110		1,479
Pro forma net earnings (loss)	$	19,248	$	(7,811	)	$	126,745	$	70,691
Net earnings (loss) applicable to common shareholders per share:
Basic -- as reported	$	.14	$	(.14	)	$	1.05	$	.72
Basic -- pro forma	$	.13	$	(.14	)	$	1.05	$	.71
Diluted -- as reported	$	.13	$	(.14	)	$	1.02	$	.71
Diluted -- pro forma	$	.13	$	(.14	)	$	1.00	$	.69

See Note VII - Stockholders’ Equity for discussion of non-cash compensation expense recorded in 2005 related to stock options.

Accumulated Other Comprehensive Income. The Company reports comprehensive income and its components in accordance with FASB Statement No. 130, Reporting Comprehensive Income. The main components of comprehensive income that relate to the Company are net earnings (loss), minimum pension liability adjustments and unrealized gain (loss) on hedging activities, all of which are presented in the Consolidated Statement of Stockholders’ Equity and Comprehensive Income.

8

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below gives an overview of comprehensive income for the periods indicated.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net earnings (loss)	$	19,590		$	(7,140	)	$	127,461		$	72,170
Other comprehensive income (loss):
Unrealized gain on hedging activities, net of tax		--			88			2,443			3,294
Realized (gain) on hedging activities in net earnings, net of tax		(34	)		(1,078	)		(1,333	)		(3,397	)
Other comprehensive income (loss)		(34	)		(990	)		1,110			(103	)
Comprehensive income (loss)	$	19,556		$	(8,130	)	$	128,571		$	72,067

Accumulated other comprehensive loss reflected in the Consolidated Balance Sheet at September 30, 2005 and December 31, 2004 includes net unrealized gains and losses, net of tax, on hedging activities and minimum pension liability adjustments.

New Accounting Pronouncements.

Southern Union’s significant accounting policies are discussed in its 2004 Transition Report on Form 10-K, as amended. The information below provides updating information or required interim disclosures with respect to those policies or disclosure where those policies have changed.

FSP No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Medicare Prescription Drug Act):Issued by the Financial Accounting Standards Board (the FASB) in May 2004, FASB Financial Staff Position (FSP) No. FAS 106-2 (FSP FAS 106-2) requires entities to record the impact of the Medicare Prescription Drug Act as an actuarial gain in the postretirement benefit obligation for postretirement benefit plans that provide drug benefits covered by that legislation. Southern Union adopted this FSP as of March 31, 2005, the effect of which was not material to the Company's consolidated financial statements. The effect of this FSP may vary as a result of any future changes to the Company's benefit plans.

FASB Statement No. 123R, “Share-Based Payment (revised 2004)”:Issued by the FASBin December 2004, the statement revises FASB Statement No. 123, Accounting for Stock-Based Compensation, supersedes Accounting Principal Board Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. This Statement will be effective for the Company beginning January 1, 2006, and will require the Company to measure all employee stock-based compensation awards using a fair value method and record such expense in its consolidated financial statements.  In addition, the adoption of this Statement will require additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. The Company is currently evaluating the impact of this Statement on its consolidated financial statements.

FSP No. FIN 46R-5, “Implicit Variable Interests under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities”:Issued by the FASB in March 2005, this Staff Position addresses whether a reporting enterprise should consider whether it holds an implicit variable interest in a variable interest entity (VIE) or potential VIE when specific conditions exist. An implicit variable interest is an implied pecuniary interest in an entity that indirectly changes with changes in the fair value of the entity's net assets exclusive of variable interests. Implicit variable interests may arise from transactions with related parties, as well as from transactions with unrelated parties.This Staff Position will be effective, for entities to which the interpretations of FIN 46(R) have been applied, beginning December 31, 2005. As of March 31, 2005 Southern Union adopted this FSP, which had no impact on its consolidated financial statements.

FIN No. 47, “Accounting for Conditional Asset Retirement Obligations”: Issued by the FASB in March 2005, this Interpretation clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the

9

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. FIN No. 47 provides guidance for assessing whether sufficient information is available to record an estimate. This Interpretation will be effective for the Company beginning on December 31, 2005. The Company is currently evaluating the impact of this Interpretation on its consolidated financial statements.

FERC Accounting Release. On June 30, 2005, the Federal Energy Regulatory Commission (FERC) issued a final order on accounting for pipeline assessment costs that requires pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs (under the Pipeline Safety Improvement Act of 2002). The accounting release determined that assessment activities associated with an integrity management program must be accounted for as maintenance and charged to expense in the period incurred. Costs associated with any remediation or rehabilitation can be capitalized. The FERC accounting guidance is to be effective January 1, 2006, for regulatory accounting purposes. Panhandle Energy (being the group of companies including Panhandle Eastern Pipe Line Company, LP (Panhandle Eastern Pipe Line), Trunkline Gas Company, LLC (Trunkline), Trunkline LNG Company, LLC (Trunkline LNG), Sea Robin Pipeline Company, LLC (Sea Robin) and Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage)) is currently reviewing the implications of the FERC accounting order, which impacts an estimated $4,000,000 of costs Panhandle Energy expects to incur in 2006 and similar annual amounts thereafter.

II. Acquisitions and Sales

On November 17, 2004, CCE Holdings, LLC (CCE Holdings), a joint venture in which Southern Union indirectly owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron Corp. and its subsidiaries for a purchase price of approximately $2,450,000,000 in cash, including certain consolidated debt. Concurrent with this transaction, CCE Holdings divested CrossCountry Energy’s interests in Northern Plains Natural Gas Company, LLC and NBP Services, LLC to ONEOK, Inc. (ONEOK) for $175,000,000 in cash. Following these transactions, CCE Holdings owns 100% of Transwestern Pipeline Company, LLC and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of Florida Gas Transmission Company. An affiliate of El Paso Corporation owns the remaining 50% of Citrus. The Company funded its $590,500,000 equity investment in CCE Holdings through borrowings of $407,000,000 under an equity bridge loan facility, net proceeds of $142,000,000 from the settlement on November 16, 2004 of its July 2004 forward sale of 8,242,500 shares of its common stock, and additional borrowings of approximately $42,000,000 under its existing revolving credit facility. Subsequently, in February 2005 Southern Union issued 2,000,000 of its 5% Equity Units from which it received net proceeds of approximately $97,378,000, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $331,772,000, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note VII - Stockholders’ Equity). The Company’s investment in CCE Holdings is accounted for using the equity method of accounting. Accordingly, Southern Union reports its share of CCE Holdings’ earnings as earnings from unconsolidated investments in the Consolidated Statement of Operations.

III. 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, warrants, restricted stock 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,
	2005		2004		2005		2004
Weighted average shares outstanding - Basic		111,032,451		84,183,300		108,721,451		81,768,052
Add assumed vesting of restricted stock		85,659		--		29,776		--
Add assumed conversion of equity units		2,305,859		--		2,139,587		401,221
Add assumed exercise of stock options		1,510,070		--		1,678,794		1,015,290
Weighted average shares outstanding - Diluted		114,934,039		84,183,300		112,569,608		83,184,563

10

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Due to its anti-dilutive effect, FASB Statement No. 128, Earnings per Share, prohibits the inclusion of potential common shares in diluted earnings per share in the period that a loss from continuing operations is incurred if the effect would be anti-dilutive. As the Company incurred a loss from continuing operations for the three months ended September 30, 2004, basic and diluted earnings per share are equal for that period.

See Note VII - Stockholders’ Equity for a discussion of restricted stock granted in 2005.

For the three months ended September 30, 2005 and 2004, “anti-dilutive” options outstanding were 15,229 and nil, respectively. For the nine months ended September 30, 2005 and 2004, “anti-dilutive” options outstanding were 51,455 and nil, respectively. At September 30, 2005, 935,819 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans and 116,543 shares of common stock were held in a rabbi trust for certain employees who deferred receipt of shares of common stock for stock options exercised. From time to time, the Company’s benefit plans may purchase shares of Southern Union common stock subject to regular restrictions.

On February 11, 2005, the Company issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit. Each equity unit consists of a 1/20^th interest in a $1,000.00 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note IX - Long-Term Debt and Capital Lease Obligations) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $23.44 and $29.30, respectively, which are subject to adjustments for future stock splits or stock dividends). Southern Union will issue between 3,413,247 shares and 4,266,558 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contracts. Until the conversion date, the equity units will have a dilutive effect on earnings per share if Southern Union’s average common stock price for the period exceeds the settlement conversion price (see Note VII - Stockholders’ Equity).

On June 11, 2003, Southern Union issued 2,500,000 of its 5.75% Equity Units at a public offering price of $50 per unit. Each equity unit consists of a $50.00 principal amount of Southern Union’s 2.75% Senior Notes due 2006 (see Note IX - Long-Term Debt and Capital Lease Obligations) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on August 16, 2006, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $13.82 and $16.86, respectively, which are subject to adjustments for future stock splits or stock dividends). Southern Union will issue between 7,413,070 shares and 9,043,945 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contracts. Until the conversion date, the equity units will have a dilutive effect on earnings per share if Southern Union’s average common stock price for the period exceeds the settlement conversion price (see Note VII - Stockholders’ Equity).

IV. Goodwill

There was no change in the carrying amount of goodwill for the nine-month period ended September 30, 2005. As of September 30, 2005, the Company has goodwill of $640,547,000 from its Distribution segment. The Distribution segment is tested at least annually for impairment.

V. Deferred Charges and Credits

	September 30,		December 31,
	2005		2004
Deferred Charges
Pensions	$	59,723	$	55,848
Derivative instrument asset		58,848		--
Unamortized debt expense		34,909		37,869
Income taxes		31,736		32,661
Retirement costs other than pensions		22,259		24,459
Environmental		18,178		16,332
Service Line Replacement program		12,757		15,161
Other		18,422		16,734
Total Deferred Charges	$	256,832	$	199,064

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of September 30, 2005 and December 31, 2004, the Company’s deferred charges include regulatory assets relating to Distribution segment operations in the aggregate amounts of $91,848,000 and $100,653,000, respectively, of which $54,312,000 and $60,611,000, respectively, is being recovered through current rates. As of September 30, 2005 and December 31, 2004, the remaining recovery period associated with these assets ranged from 1 month to 190 months and from 1 month to 199 months, respectively. None of these regulatory assets, which primarily relate to pensions, retirement costs other than pensions, income taxes, Year 2000 costs, Missouri Gas Energy’s service line replacement program and environmental remediation costs, are included in rate base. The Company records regulatory assets in accordance with FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation.

	September 30,		December 31,
	2005		2004
Deferred Credits
Pensions	$	106,786	$	109,908
Retirement costs other than pensions		57,101		58,507
Cost of removal		30,563		29,337
Environmental		26,047		25,919
Provision for claims		21,235		20,686
Customer advances for construction		15,725		14,740
Derivative instrument liability		6,203		16,232
Investment tax credit		4,710		5,027
Other		35,025		40,693
Total Deferred Credits	$	303,395	$	321,049

As of September 30, 2005 and December 31, 2004, the Company’s deferred credits include regulatory liabilities relating to Distribution segment operations in the aggregate amounts of $10,415,000 and $15,285,000, respectively. These regulatory liabilities primarily relate to retirement costs other than pensions, environmental insurance recoveries and income taxes. The Company records regulatory liabilities in accordance with FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation.

VI. Unconsolidated Investments

	September 30, 2005		December 31, 2004
Unconsolidated Investments
Equity investments:
CCE Holdings	$	673,244	$	615,861
Other		13,069		12,919
Investments at cost		2,605		3,113
Total unconsolidated investments	$	688,918	$	631,893

Equity Investments. Unconsolidated investments include the Company’s 50%, 29% and 49.9% investments in CCE Holdings, Lee 8 and PEI Power II, respectively, which are accounted for using the equity method. The Company’s share of net income or loss from these equity investments is recorded in earnings from unconsolidated investments in the Consolidated Statement of Operations. The Company’s equity investment balances include purchase price differences of $20,700,000 and $20,716,000 as of September 30, 2005 and December 31, 2004, respectively. The purchase price differences represent the excess of the purchase price over the Company’s share of the investee’s book value at the time of acquisition and, accordingly, have been designated as goodwill that will be accounted for pursuant to Accounting Principles Board (APB) Opinion 18, The Equity Method of Accounting for Investments in Common Stock, and FASB Statement No. 142, Goodwill and Other Intangible Assets.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized financial information for the Company’s equity investments were:

	Three Months Ended				Nine Months Ended
	September 30, 2005				September 30, 2005
	CCE Holdings		Other		CCE Holdings		Other
Income Statement Data:
Revenues	$	63,780	$	3,161	$	175,437	$	5,470
Operating income		36,913		703		96,856		1,098
Net income		43,710		660		115,485		964

Other Investments, at Cost. As of September 30, 2005, the Company, either directly or through a subsidiary, owned common and preferred stock in two non-public companies, Advent Networks, Inc. (Advent) and PointServe, Inc. (PointServe), whose fair values are not readily determinable. These investments are accounted for under the cost method. Realized gains and losses on sales of these investments, as determined on a specific identification basis, are included in the Consolidated Statement of Operations when incurred, and dividends are recognized as income when received. Various Southern Union executive management, members of its Board of Directors and employees either directly or through a partnership also have an equity ownership in Advent.

On March 24, 2005, Advent’s Board of Directors approved the filing of a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the Western District of Texas (the Bankruptcy Court). As a result, Southern Union recorded a $4,000,000 liability associated with the guarantee by a subsidiary of the Company of a line of credit between Advent and a bank in the first quarter of 2005. On April 8, 2005, which was subsequent to the bankruptcy filing, Advent defaulted on its $4,000,000 line of credit and the guarantee liability was funded. Also as of March 31, 2005, the Company recorded a $508,000 other-than-temporary impairment of its remaining unreserved investment in Advent. The total charge of $4,508,000 was reflected in Other income, net in the Consolidated Statement of Operations for the quarter ended March 31, 2005.

The Company reviews its portfolio of unconsolidated investment securities on a quarterly basis to determine whether a decline in value is other-than-temporary. Factors that are considered in assessing whether a decline in value is other-than-temporary include, but are not limited to, the following: earnings trends and asset quality; near term prospects and financial condition of the issuer, including the availability and terms of any additional financing requirements; financial condition and prospects of the issuer's region and industry, customers and markets and Southern Union's intent and ability to retain the investment. If Southern Union determines that the decline in value of an investment security is other-than-temporary, the Company will record a charge in its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value.

VII. Stockholders’ Equity

Stock Splits and Dividends. On September 1, 2005, Southern Union distributed a 5% common stock dividend to stockholders of record on August 22, 2005. Unless otherwise stated, all per share and share data included herein have been restated to give effect to the dividend.

Common Stock. On May 9, 2005, the stockholders of the Company adopted the Southern Union Company Amended and Restated Stock and Incentive Plan (the Amended 2003 Plan). The Amended 2003 Plan allows for awards in the form of stock options (either incentive stock options or non-qualified options), stock appreciation rights, stock bonus awards, restricted stock, performance units or other equity-based rights. The persons eligible to receive awards under the Amended 2003 Plan include all of the employees, directors, officers and agents of, and other service providers to, the Company and its affiliates and subsidiaries. The Amended 2003 Plan provides that each non-employee director will receive annually a restricted stock award or at the election of the non-employee director options having an equivalent value, which will be granted at such time or times as the Compensation Committee shall determine. Under the Amended 2003 Plan: (i) no participant may receive in any calendar year awards covering more than 500,000 shares; (ii) the exercise price for a stock option may not be less than 100% of the fair market value of

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the stock on the date of grant; and (iii) no award may be granted more than ten years after the date of the Amended 2003 Plan.

On June 27, 2005, pursuant to the Amended 2003 Plan, Southern Union granted 34,295 restricted shares of its common stock to its Interim General Counsel and granted 4,200 restricted shares of its common stock to each of the seven non-management members of its Board of Directors. The individual shares awarded on June 27, 2005 will vest in full on January 2, 2006, provided that certain conditions are met. Also on June 27, 2005, Southern Union granted options to purchase up to 262,500 shares of its common stock under the Amended 2003 Plan at an exercise price of $23.62 to its Interim General Counsel. The stock options subject to this award are fully vested and remain exercisable for a period of ten years from the date of the grant. On July 5, 2005, Southern Union granted options to purchase up to 105,000 shares of its common stock under the Amended 2003 Plan at an exercise price of $23.89 to its Senior Vice President & Chief Financial Officer. The stock options subject to this award will vest in 20% increments each year commencing on the first anniversary of the grant date and will expire on July 5, 2015. On July 27, 2005, Southern Union granted, under the Amended 2003 Plan, 79,275 restricted shares of its common stock and options to purchase up to 51,547 shares of its common stock at an exercise price of $24.06 to certain officers of the Company, its subsidiaries and affiliates. The individual restricted shares awarded will vest in equal percentages over the next four years provided the applicable recipient remains an employee of the Company, its subsidiary or affiliate. The stock options subject to the award will also vest in equal percentages over the next four years and will remain exercisable for a period of ten years from the grant date. On August 16, 2005, Southern Union granted options to purchase up to 21,000 shares of its common stock under the Amended 2003 Plan at an exercise price of $24.50 to its Senior Vice President of Utility Operations. The stock options subject to this award will vest in 20% increments each year commencing on the first anniversary of the grant date and will expire on August 16, 2015. Each of the grants above has been restated to give effect to the September 1, 2005 stock dividend. On September 2, 2005, pursuant to the Amended 2003 Plan, Southern Union granted 3,200 restricted shares of its common stock and options to purchase up to 15,000 shares of its common stock at an exercise price of $24.80 to its Vice President-Controller & Chief Accounting Officer. The stock options subject to this award will vest in 25% increments each year commencing on the first anniversary of the grant date and will expire on September 2, 2015. On September 28, 2005, Southern Union granted, under the Amended 2003 Plan, 2,000 restricted shares of its common stock and options to purchase up to 1,300 shares of its common stock at an exercise price of $24.25 to certain officers of the Company, its subsidiaries and affiliates. The stock options subject to this award will vest in 25% increments each year commencing on September 22, 2005 and will expire on September 22, 2015.

On July 1, 2005, pursuant to the respective separation agreements between the Company and its former Vice Chairman of the Board of Directors and former Chief Financial Officer, the Company modified the terms of approximately 307,000 options to purchase its common stock that had previously been granted to and were exercisable by these executives under the Company’s 1992 Long-Term Stock Incentive Plan and Amended 2003 Plan. The options subject to this modification now remain exercisable for a period of 18 months from the executives’ respective termination dates. As a result of the modification and re-valuation of the options as of July 1, 2005, the Company recorded $3,848,000 of non-cash compensation expense during the quarter ended September 30, 2005.

February 2005 Equity Issuances. On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $97,378,000. Southern Union used the proceeds to repay the balance of the bridge loan used to finance a portion of its investment in CCE Holdings and to repay borrowings under its credit facilities. Each equity unit consists of a 1/20^th interest in a $1,000.00 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note IX - Long-Term Debt and Capital Lease Obligations) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $23.44 and $29.30, respectively, which are subject to adjustments for future stock splits or stock dividends). The equity units carry a total annual coupon of 5.00% (4.375% annual face amount of the senior notes plus 0.625% annual contract adjustment payments). The present value of the equity units’ contract adjustment payments was initially charged to shareholders’ equity, with an offsetting credit to liabilities. The liability is accreted over three years by interest charges to the Consolidated Statement of Operations. Before the issuance of Southern Union’s common

14

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

stock upon settlement of the purchase contracts, the purchase contracts will be reflected in the Company’s diluted earnings per share calculations using the treasury stock method.

On February 9, 2005, Southern Union issued 14,913,042 shares of its common stock at $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $331,772,000. Southern Union used the net proceeds to repay a portion of the bridge loan used to finance a portion of its investment in CCE Holdings.

July 2004 Equity Issuances. On July 30, 2004, Southern Union issued 4,800,000 shares of its common stock at the public offering price of $18.75 per share, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $86,563,000. Southern Union also sold 6,200,000 shares of its common stock through forward sale agreements with its underwriters and granted the underwriters a 30-day over-allotment option to purchase up to an additional 1,650,000 shares of its common stock at the same price, which was exercised by the underwriters. Under the terms of the forward sale agreements, Southern Union had the option to settle its obligation to the forward purchasers through either (i) paying a net settlement in cash, (ii) delivering an equivalent number of shares of its common stock to satisfy its net settlement obligation, or (iii) the physical delivery of shares. Upon settlement, which occurred on November 16, 2004, Southern Union received approximately $142,000,000 in net proceeds upon the issuance of 8,242,500 shares of common stock to affiliates of JP Morgan and Merrill Lynch, joint book-running managers of the offering. Southern Union used the total net proceeds from the settlement of the forward sale agreements to fund a portion of its investment in CCE Holdings.

VIII. Derivative Instruments and Hedging Activities

The Company utilizes derivative instruments on a limited basis to manage certain business risks. Interest rate swaps are used to reduce interest rate risks and to manage interest expense.

Cash Flow Hedges. On April 29, 2005, the Company refinanced the existing bank loans of Trunkline LNG Holdings, LLC (LNG Holdings) in the amount of $255,626,000, due 2007 (see Note IX - Long-Term Debt and Capital Lease Obligations). 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 $3,465,000 ($2,072,000 net of tax) was recorded in Accumulated other comprehensive income during the second quarter of 2005 and is being amortized to interest expense through the maturity date of the original bank loans in 2007. From January 1, 2005 through the termination date of the swap agreements on April 29, 2005, there was no swap ineffectiveness. For the three and nine months ended September 30, 2004, the amount of swap ineffectiveness was not significant.

In March and April 2003, the Company entered into a series of treasury rate locks with an aggregate notional amount of $250,000,000 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 $6,862,000 after-tax loss that was recorded in Accumulated other comprehensive income and will be amortized into interest expense over the lives of the associated debt instruments. As of September 30, 2005, approximately $967,000 of net after-tax losses in Accumulated other comprehensive income will be amortized into interest expense during the next twelve months.

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.

Fair Value Hedges. In March 2004, Panhandle Energy entered into interest rate swaps to hedge the risk associated with the fair value of its $200,000,000 of 2.75% Senior Notes. These swaps are designated as fair value hedges and qualify for the short cut method under FASB Statement No.133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under the swap agreements, Panhandle Energy will receive fixed interest payments at a rate of 2.75% per annum and will make floating interest payments based on the six-month LIBOR. No ineffectiveness is assumed in the hedging relationship between the debt instrument and the interest rate swap. As of September 30, 2005 and December 31, 2004, the fair values of the swaps are included in the Consolidated Balance Sheet as liabilities with matching adjustments to the underlying debt of $6,203,000 and $3,936,000, respectively.

15

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Non-Hedging Activities. During 2004 and 2005, the Company entered into natural gas commodity swaps and collars in order to mitigate price volatility of natural gas passed through to utility customers. 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 value of the contracts is recorded as an adjustment to a regulatory asset/liability in the Consolidated Balance Sheet. As of September 30, 2005 and December 31, 2004, the fair values of the contracts, which expire at various times through October 2006, are included in the Consolidated Balance Sheet as an asset and liability, respectively, with matching adjustments to deferred cost of gas of $58,848,000 and $2,597,000, respectively.

IX. Long-Term Debt and Capital Lease Obligations

The following table sets forth the long-term debt and capital lease obligations, including the current portions thereof, of Southern Union and Panhandle Energy under their respective notes, debentures and bonds at the dates indicated:

	September 30,		December 31,
	2005		2004
Southern Union Company
7.60% Senior Notes, due 2024	$	359,765	$	359,765
8.25% Senior Notes, due 2029		300,000		300,000
2.75% Senior Notes, due 2006		125,000		125,000
4.375% Senior Notes, due 2008		100,000		--
Term Note, due 2005		--		76,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029		111,419		112,421
Capital lease due 2005 to 2007		78		117
		996,262		973,390
Panhandle Energy
2.75% Senior Notes due 2007		200,000		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
LNG Holdings’ bank loans due 2007		255,626		258,433
Unamortized debt premium, net		12,835		14,688
		1,185,889		1,190,549
Total consolidated long-term debt and capital lease obligations		2,182,151		2,163,939
Less current portion		126,648		89,650
Less fair value swaps of Panhandle Energy		6,203		3,936
Total consolidated long-term debt and capital lease obligations	$	2,049,300	$	2,070,353

The Company has $2,182,151,000 of long-term debt recorded at September 30, 2005. Debt of $1,726,525,000, including net premiums of $12,835,000 and unamortized interest rate swaps of $6,203,000, is at annual fixed rates ranging from 2.75% to 10.25%. The Company also has floating rate debt of $728,626,000, including notes payable of $273,000,000 (see Note X - Notes Payable), bearing an average rate of 5.14% as of September 30, 2005. The variable rate bank loans are unsecured.

As of September 30, 2005, the Company has scheduled debt and capital lease payments of nil, $126,648,000, $457,274,000, $401,646,000, $61,998,000 and $1,121,750,000 due during the remainder of 2005 and for years 2006 through 2009 and thereafter, respectively.

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

The Company is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating. Certain covenants exist in certain of the Company’s debt agreements that require the Company to maintain a certain level of net worth, to meet certain debt to total capitalization ratios, and

16

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by the Company to satisfy any such covenant would be considered an event of default under the associated debt, which could become immediately due and payable if the Company did not cure such default within any permitted cure period or if the Company did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Term Note. On July 16, 2002, the Company issued a $311,087,000 Term Note dated July 15, 2002 (the 2002 Term Note). The 2002 Term Note carried a variable interest rate that was tied to either the LIBOR or prime interest rates at the Company’s option. During the quarter ended June 30, 2005, the Company repaid the remaining $76,087,000 principal outstanding under the 2002 Term Note and, as of June 2, 2005, the 2002 Term Note was canceled.

Panhandle Energy Refinancing. On April 29, 2005, Panhandle Energy refinanced LNG Holdings’ outstanding bank loans of $255,626,000, due 2007, for the same principal amount and extended the maturity date from January 31, 2007 to March 15, 2007. The new notes have substantially the same terms as the old notes with the exception of the following primary differences: (i) the assets of Trunkline LNG are not pledged as collateral; (ii) Panhandle Eastern Pipe Line and Trunkline LNG each severally provided a guarantee for the notes; and (iii) the interest rate is tied to the rating of Panhandle Eastern Pipe Line’s unsecured funded debt. As of September 30, 2005, the interest rate on the LNG Holdings’ bank loans was 4.47%.

On March 12, 2004, Panhandle Energy issued $200,000,000 of its 2.75% Senior Notes due 2007. Panhandle Energy used a portion of the net proceeds of that offering to fund the redemption of the remaining $146,080,000 principal amount of its 6.125% Senior Notes due 2004 that matured on March 15, 2004, and to provide working capital to the Company. Panhandle Energy used a portion of the remaining net proceeds to repay the remaining $52,455,000 principal amount of its 7.875% Senior Notes due 2004 that matured on August 15, 2004.

X. Notes Payable

On September 29, 2005, the Company entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400,000,000 (the Long-Term Facility). The Long-Term Facility has a five-year term and matures on May 28, 2010. The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount. Borrowings under the Long-Term Facility are available for Southern Union’s working capital, letter of credit requirements and other general corporate purposes. The Company has additional availability under uncommitted line of credit facilities (Uncommitted Facilities) with various banks. The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (the Senior Notes). As of September 30, 2005, the commitment fees were an annualized 0.11%.

On July 14, 2005, the Company amended an existing uncommitted short-term bank note to increase the principal amount from $15,000,000 to $65,000,000 in order to provide additional liquidity. The note is repayable upon demand and the Company borrowed $50,000,000 under the note on July 19, 2005 for an initial period of six months at a rate of 4.54%, which is based upon six-month LIBOR plus 70 basis points.

Balances of $273,000,000 and $292,000,000 were outstanding under the Company’s credit facilities at effective interest rates of 6.25% and 3.20% at September 30, 2005 and December 31, 2004, respectively. As of October 28, 2005, there was a balance of $305,000,000 outstanding under the Company’s credit facilities at an effective interest rate of 4.59%.

On November 17, 2004, an indirect, wholly-owned subsidiary of the Company entered into a $407,000,000 Bridge Loan Agreement (the Bridge Loan) with a group of three banks in order to provide a portion of the funding for the Company’s investment in CCE Holdings. The Bridge Loan had a maturity date of May 17, 2005 and bore interest at LIBOR plus 1.25%. The Bridge Loan was repaid in February 2005 with the proceeds from the Company’s offerings of its common stock and equity units, as required under the terms of the Bridge Loan agreement.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

XI. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the three months ended September 30, 2005 and 2004 includes the following components:

	Pension Benefits						Postretirement Benefits
	2005			2004			2005			2004
Service cost	$	2,485		$	1,956		$	1,102		$	1,144
Interest cost		6,805			5,693			2,147			2,344
Expected return on plan assets		(7,529	)		(6,031	)		(760	)		(588	)
Amortization of prior service cost		345			381			35			163
Recognized actuarial loss		3,148			2,051			116			225
Curtailment recognition		--			--			--			--
Settlement recognition		(251	)		94			--			--
Sub-Total		5,003			4,144			2,640			3,288
Regulatory adjustment		(5,919	)		--			(57	)		(57	)
Net periodic benefit cost	$	(916	)	$	4,144		$	2,583		$	3,231

Net periodic benefit cost for the nine months ended September 30, 2005 and 2004 includes the following components:

	Pension Benefits						Postretirement Benefits
	2005			2004			2005			2004
Service cost	$	6,491		$	5,014		$	3,296		$	3,312
Interest cost		17,915			17,112			6,475			7,133
Expected return on plan assets		(19,623	)		(17,021	)		(2,045	)		(1,391	)
Amortization of prior service cost		1,001			1,002			168			392
Recognized actuarial loss		8,198			6,640			677			423
Curtailment recognition		3,107			--			--			--
Settlement recognition		(589	)		(114	)		--			--
Sub-Total		16,500			12,633			8,571			9,869
Regulatory adjustment		(5,919	)		--			(171	)		(101	)
Net periodic benefit cost	$	10,581		$	12,633		$	8,400		$	9,768

In the Distribution segment, the Company recovers certain qualified pension plan and postretirement benefit plan costs through rates to utility customers. Certain utility commissions require that the recovery of pension costs be based on ERISA or other utility commission specific guidelines. The difference between these amounts and pension expense calculated pursuant to FASB Statement No. 87 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.

Employer Contributions. For the nine months ended September 30, 2005, the Company contributed approximately $5,300,000 and $7,500,000 to the Company’s pension plans and postretirement plans, respectively.

Recently Enacted Legislation. The Medicare Prescription Drug Act was signed into law December 8, 2003. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy, which is not taxable, to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Issued by the FASB in May 2004, FSP FAS 106-2 requires entities to record the impact of the Medicare Prescription Drug Act as an actuarial gain in the postretirement benefit obligation for postretirement benefit plans that provide drug benefits covered by that legislation. Southern Union adopted this FSP as of March 31, 2005, the effect of which was not material to the Company's consolidated financial statements. The effect of this FSP may vary as a result of any future changes to the Company's benefit plans.

Benefit Plan Termination. Effective June 30, 2005, the Company terminated its 1997 Supplemental Retirement Plan (the Supplemental Plan), which was a non-contributory cash balance retirement plan for certain current and former executive employees of the Company. As a result, the Company had an estimated pension net loss of $1,334,000

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comprised of a $1,585,000 loss on pension curtailment, recognized in the second quarter of 2005, and a $251,000 gain on pension settlement, recognized in the third quarter of 2005. Prior to the termination of the Supplemental Plan, the Company also recorded a $1,141,000 loss on pension curtailment in the second quarter of 2005 that was triggered by pension payments made to a former executive of the Company under this plan.

Also effective June 30, 2005, the Company terminated its 2000 Executive Deferred Stock Plan, which was a defined contribution deferred compensation plan for certain management and highly compensated employees. The plan’s assets are held in a rabbi trust and will be distributed to participants during the fourth quarter of 2005. The termination of this plan will not have a material effect on the Company’s consolidated financial statements.

Benefit Plan Changes. Certain changes have been approved in the fourth quarter of 2005 relating to Panhandle Energy’s postretirement health care plan to go into effect in 2006 which are expected to reduce Panhandle Energy’s accumulated postretirement benefit obligation by approximately $20,000,000 and future expenses by approximately $1,000,000 per quarter.

XII. Taxes on Income

The Company's estimated annual consolidated federal and state effective income tax rate (Estimated EITR) for 2005 is 29% as of September 30, 2005. The Company’s Estimated EITR for 2004 was 37% as of September 30, 2004. The decrease in the Estimated EITR was primarily due to: (i) the anticipated reversal, during 2005, of an $11,942,000 deferred tax asset valuation allowance associated with Southern Union's investment in CCE Holdings; (ii) the recognition of an 80% dividend received deduction on dividends expected to be received from Citrus during 2005; and (iii) the recognition of the Medicare Part D tax-free subsidy (see Note XI - Employee Benefits).

Southern Union is nearing completion of an income tax project assessing substantially all its temporary differences. The Company believes that this project will be completed by December 31, 2005. Upon the completion of this project, the Company may identify deferred income tax assets or liabilities that may be adjusted and could result in a decrease or increase in income tax expense. Management does not believe that the effect of such adjustments will have a material effect on the Company's consolidated financial statements.

XIII. Regulation and Rates

Missouri Gas Energy. On September 21, 2004, the Missouri Public Service Commission (the MPSC) issued a rate order authorizing the Missouri Gas Energy division of Southern Union (MGE) to increase its base revenues by $22,370,000, effective October 2, 2004. The rate order, based on a 10.5% return on equity, also produced an improved rate design that the Company believes should help stabilize revenue streams and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between MGE and its customers.

On October 20, 2004, MGE filed a writ of review with the Cole County Circuit Court regarding the MPSC’s October 2004 rate order. MGE is seeking base revenues in addition to the increase cited above on grounds that the capital structure and 10.5% return on equity used by the MPSC in determining such increase do not provide an adequate rate of return. Upon judicial review, the Cole County Circuit Court issued an opinion in March 2005 agreeing with MGE’s claims and remanding the matter to the MPSC for reconsideration. On April 8, 2005, the MPSC appealed the Cole County Circuit Court’s ruling to the Missouri Court of Appeals - Western District.

The $22,370,000 increase in base revenues under the MPSC’s October 2004 rate order continues to be in effect, but may be increased depending upon the ruling of the Missouri Court of Appeals and any subsequent rate order review the MPSC is required to perform. The Company cannot currently predict the outcome of this matter.

Panhandle Energy. In December 2002, FERC approved a certificate application by Trunkline LNG to expand the Lake Charles liquefied natural gas (LNG) terminal to approximately 1.2 billion cubic feet (Bcf) per day of sustainable send out capacity versus the current sustainable send out capacity of .63 Bcf per day and to increase terminal storage capacity to 9 Bcf from the current 6.3 Bcf (Phase I). BG LNG Services has contract rights for the .57 Bcf per day of additional send out capacity. On September 18, 2005, the Company placed in service the expanded vaporization

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capacity portion of the expansion. The Company expects that construction on Phase I of the Trunkline LNG expansion project, which commenced in September 2003, will be completed at an estimated cost of $137,000,000, plus capitalized interest, in early 2006 (see Note XIV - Commitments and Contingencies). On September 23, 2004, FERC gave final approval to Trunkline LNG’s further incremental LNG expansion project (Phase II). The Company estimates that Phase II will cost approximately $82,000,000, plus capitalized interest, and will increase the LNG terminal’s sustainable send out capacity to 1.8 Bcf per day. The Company expects Phase II to be in-service by the middle of 2006. BG LNG Services has contracted for all the proposed additional capacity to be provided in both Phase I and Phase II, subject to Trunkline LNG achieving certain construction milestones in the expansion of this facility. Approximately $131,000,000 and $127,000,000 of costs are included in the line item Construction Work In Progress for the expansion projects at September 30, 2005 and December 31, 2004, respectively.

On February 11, 2005 Trunkline received approval from FERC to construct, own and operate a 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal. The pipeline creates additional transport capacity in association with the Trunkline LNG expansion and also includes new and expanded delivery points with major interstate pipelines. The new 36-inch pipeline was placed into service on July 22, 2005.

XIV. 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. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations. These evolving laws and regulations may require expenditures over a long period of time to con-trol environmental impacts. The Company is currently updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.

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.

In certain of the Company’s jurisdictions, the Company is allowed to recover environmental remediation expenditures through rates. 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 financial position, results of operations or cash flows.

Local Distribution Company Environmental Matters.

Prior to the availability of natural gas, many cities had Manufactured Gas Plants (MGPs) that produced a fuel known as “town gas”. Some constituents of the manufactured gas process may be regulated substances under various federal and state environmental laws. To the extent these constituents are present in soil or groundwater at concentrations in excess of applicable standards, investigation and remediation may be required. The Company is investigating the possibility that the Company or predecessor companies may have been associated with MGP sites in its former gas distribution service territories, principally in Texas, Arizona and New Mexico, and present gas distribution service territories in Missouri, Pennsylvania, Massachusetts and Rhode Island. The Company is aware of certain MGP sites in these areas and is investigating those and certain other locations. To the extent that potential costs associated with former MGPs are quantified, the Company expects to provide any appropriate accruals and seek recovery for such remediation costs through all appropriate means, including in rates charged to gas distribution customers, insurance and regulatory relief. At the time of the closing of the acquisition of the Company's Missouri service territories, the Company entered into an Environmental Liability Agreement that provides that Western Resources retains financial responsibility for certain liabilities under environmental laws that may exist or arise with respect to MGE. In addition, the New England Gas Company division of Southern Union (NEGC) has reached agreement with its Rhode Island rate regulators on a regulatory plan that creates a mechanism for the recovery of environmental costs over a ten-year period. This plan, effective July 1, 2002, establishes an environmental fund for

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the recovery of evaluation, remedial and clean-up costs arising out of the Company's MGPs and sites associated with the operation and disposal activities from MGPs. Similarly, environmental costs associated with NEGC’s Massachusetts’ facilities are recoverable in rates over a seven-year period.

While the Company's evaluation of these Texas, Missouri, Arizona, New Mexico, Pennsylvania, Massachusetts and Rhode Island MGP sites is in its preliminary stages, it is likely that some compliance costs may be identified and become subject to reasonable quantification. Within the Company's gas distribution service territories certain MGP sites are currently the subject of governmental actions. These sites are as follows:

Missouri Gas Energy.

Kansas City, Missouri Site - In a letter dated May 10, 1999, the Missouri Department of Natural Resources (MDNR) sent notice of a planned Site Inspection/Removal Site Evaluation of the Kansas City Coal Gas former MGP site. This site (comprised of two adjacent MGP operations previously owned by two separate companies and hereafter referred to as Station A and Station B) is located at East 1^st Street and Campbell in Kansas City, Missouri and is owned by MGE. During July 1999, the Company entered the two sites into MDNR’s Voluntary Cleanup Program (VCP) and, subsequently, performed environmental assessments of the sites. Following the review of these assessments, MDNR required MGE to initiate remediation of Station A. The Company began remediation of Station A in the first calendar quarter of 2003 and completed the project in July 2003, at an approximate cost of $4,000,000. MDNR issued a conditional No Further Action letter for Station A-South on July 22, 2004. MGE received a letter from MDNR dated April 11, 2005 requesting that MGE conduct additional investigation activities to determine what areas of the groundwater plume exceed state standards (Missouri Risk-Based Corrective Action Guidance); determine if data gaps exist in the monitoring well array; and determine if additional soil cleanup is needed in areas not addressed during the Station A-South cleanup. MGE will submit a work plan to MDNR to complete the above-requested items.

MDNR has also stated that some remedial actions may be necessary on Station B to remove tar material found during the 1999 site investigation.

St. Joseph, Missouri Site - Following a failed tank tightness test, MGE removed an underground storage tank (UST) system in December 2002 from a former MGP site in St. Joseph, Missouri. A UST closure report was filed with MDNR on August 12, 2003. In a letter dated September 26, 2003, MDNR indicated that its review of the analytical data submitted for this site indicated that contamination existed in the site above the levels specified in Missouri guidance documents. MGE submitted a UST Site Characterization Work Plan that was approved by MDNR on August 20, 2004. The site characterization fieldwork was completed in December 2004 and a report was submitted to MDNR in March 2005. MGE received a letter response from MDNR dated May 17, 2005 requesting that additional characterization of soil and groundwater contamination be conducted and that a work plan be submitted within 30 days. MGE requested and received an extension to submit the work plan, and the Supplemental Site Characterization Work Plan was submitted on July 15, 2005. As a result of a meeting held on August 26, 2005, MGE submitted revised scopes of work and cost estimates in September to the MDNR and the Petroleum Storage Tank Insurance Fund (PSTIF). Discussions are ongoing with the PSTIF as part of the cost of the investigation should be recoverable from the PSTIF. MGE is awaiting a response to the September submittals by the MDNR.

New England Gas Company.

642 Allens Avenue, Providence, Rhode Island Site - Prior to its acquisition by the Company, Providence Gas performed environmental studies and initiated an environmental remediation project at Providence Gas’ primary gas distribution facility located at 642 Allens Avenue in Providence, Rhode Island. Providence Gas spent more than $13,000,000 on environmental assessment and remediation at this MGP site under the supervision of the Rhode Island Department of Environmental Management (RIDEM). Remediation was completed in October 2002, and a Closure Report was filed with RIDEM in December 2002. The cost of environmental work conducted after remediation resumed was $4,000,000. Remediation of the remaining 37.5 acres of the site (known as the “Phase 2” remediation project) is not scheduled at this time. The Company is continuing with groundwater monitoring and limited soil removal, as necessary. Until NEGC receives a closure letter from RIDEM, it is unclear what, if any, additional investigation or remediation will be necessary. The Company is currently preparing to decommission two

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former gas holders that exist at this site. Before the holders can be removed, they must be drained of collected stormwater and cleaned. Discharge of the collected stormwater is expected to begin in December 2005 and extend through 2006, at which time the holders will be cleaned and the holder shells can be dismantled.

170 Allens Avenue, Providence, Rhode Island Site - In November 1998, Providence Gas received a letter of responsibility from RIDEM relating to possible contamination at a site that operated as an MGP in the early 1900s in Providence, Rhode Island. Subsequent to its use as a MGP, this site was operated for over 80 years as a bulk fuel oil storage yard by a succession of companies including Cargill, Inc. (Cargill). Cargill has also received a letter of responsibility from RIDEM for the site. An investigation has begun to determine the extent of contamination, as well as the extent of the Company’s responsibility. Providence Gas entered into a cost-sharing agreement with Cargill, under which Providence Gas is responsible for approximately 20% of the costs related to the investigation. Until RIDEM provides its final response to the investigation, and the Company knows its ultimate responsibility in relation to other potentially responsible parties with respect to the site, the Company cannot offer any conclusions as to its ultimate financial responsibility with respect to the site.

Cory’s Lane, Tiverton, Rhode Island Site - Fall River Gas Company (acquired in September 2000 by the Company) was a defendant in a civil action seeking to recover anticipated remediation costs associated with contamination found at a property owned by the plaintiffs (Cory’s Lane Site) in Tiverton, Rhode Island. This claim was based on alleged dumping of material by Fall River Gas Company trucks at the site in the 1930s and 1940s. In a settlement agreement effective December 3, 2001, the Company agreed to perform all assessment, remediation and monitoring activities at the Cory’s Lane Site sufficient to obtain a final letter of compliance from RIDEM. Following the performance of a site investigation, NEGC submitted a Site Investigation Report to RIDEM in December 2003. On April 15, 2004, NEGC obtained verbal approval from RIDEM to conduct additional investigation activity and the report detailing this additional investigation work was submitted to RIDEM on April 14, 2005. NEGC has proposed to make necessary improvements to the roadway and existing culvert as well as to monitor the groundwater and surface water within the subject area. The Company is currently awaiting approval from RIDEM of the April 14, 2005 Site Investigation Report including the proposed remedy.

Bay Street, Tiverton, Rhode Island Site - On March 17, 2003, RIDEM sent NEGC a letter of responsibility pertaining to alleged historical MGP impacted soils in a residential neighborhood along Bay and Judson Streets (Bay Street Area) in Tiverton, Rhode Island. The letter requested that NEGC prepare a Site Investigation Work Plan and subsequently perform a Site Investigation of the Bay Street Area. Without admitting responsibility or accepting liability, NEGC began assessment work in June 2003. NEGC has continued to perform assessment field work since that time, and filed a progress report with RIDEM updating the status of the project on May 2, 2005. NEGC received a letter from RIDEM dated May 17, 2005 stating that a completed Site Investigation Report must be submitted by July 30, 2005, which was subsequently extended to August 15, 2005. NEGC submitted a Supplemental and Phase 2 Site Investigation Report on August 15, 2005 proposing a human health risk assessment be conducted prior to the selection of any final remedial alternatives for properties exhibiting exceedances of RIDEM criteria; recommending RIDEM issue No Further Action letters for properties at which no exceedances of RIDEM criteria were observed; and requesting RIDEM’s assistance to access properties which have not yet granted access. The Report also identified incomplete information and other factors contributing to the preliminary nature of the report and informed RIDEM that NEGC would be reassessing its role in volunteering to participate in the site investigation process in light of the litigation described below. Subsequent to submitting its Site Investigation Reports, NEGC received from RIDEM a concurrence for limited additional proposed sampling, but has not yet received written comments from RIDEM to the August 15, 2005 Reports.

On May 2, 2005, the Company was served with a complaint filed on behalf of plaintiffs against NEGC in the Superior Court of Providence, Rhode Island, alleging certain grounds and claims for damages as a result of previous events that occurred in Tiverton, Rhode Island. 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. On June 2, 2005, the Company was served with a second multi-plaintiff lawsuit filed in the Superior Court of Newport County, Rhode Island in which the plaintiffs make similar claims. On August 18, 2005, the Company was served with a third complaint having similar claims filed in Newport County, Rhode Island on behalf of five individuals. The Company has removed all three lawsuits to Rhode Island federal court and has filed Motions to Dismiss. On or about September

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19, 2005, the Company was served with a fourth lawsuit, also with similar claims, filed in the Superior Court of Bristol County, Massachusetts on behalf of 17 plaintiffs. The Company has succeeded in removal of this action to Massachusetts federal court and is currently seeking its transfer to Rhode Island federal court. The Company will vigorously defend itself against all four lawsuits. Parts of the Bay Street Area appear to have been built on fill placed at various times and include one or more historic waste disposal sites. Research is therefore underway by the Company to identify other potentially responsible parties associated with the fill materials and the waste disposal. Based upon its current understanding of the facts, the Company does not believe the outcome of these matters will have a material adverse effect on its financial position, results of operation or cash flow.

Mt. Hope Street, North Attleboro, Massachusetts Site - In 2003, NEGC conducted a Phase I environmental site assessment at a former MGP site in North Attleboro, Massachusetts (the Mt. Hope Street Site) to determine if the property could be redeveloped as a service center. During the site walk, coal tar was found in the adjacent creek bed, and notice to the Massachusetts Department of Environmental Protection (MADEP) was made. On September 18, 2003, a Phase I Initial Site Investigation Report and Tier Classification were submitted to MADEP. The site was ranked as Tier 2 using MADEP’s Numerical Ranking System (NRS) criteria. The Phase I report recommended further investigation and submittal of a Phase II Comprehensive Site Assessment Report. On November 25, 2003, MADEP issued a Notice of Responsibility letter to NEGC. Two conditions identified during the investigation activities, the presence of greater than half an inch of non-aqueous phase liquid (NAPL) in an onsite well, and elevated polycyclic aromatic hydrocarbons (PAHs) in sediment samples collected adjacent to the property, are the subject of current Immediate Response Actions (IRA) at the site. An IRA Plan proposing investigation activities associated with these conditions was submitted to MADEP on January 21, 2005. Using Phase II investigation data, the MADEP NRS score sheet was revised and necessitated the reclassification of the site from Tier 2 to Tier 1C. An IRA Status Report, revised NRS score sheet, Tier Classification documentation and Application for Tier 1C Permit were submitted to MADEP on March 23, 2005. In order to implement the portion of the IRA Plan specific to the elevated PAHs in sediment, samples must be collected at properties not owned or controlled by the Company. Due to the lack of access to offsite properties beyond its control, NEGC filed an interim Phase II Report and a preliminary Phase III Remedial Action Plan with MADEP on September 23, 2005. NEGC will supplement the Phase II and Phase III reports when the results of the off-site investigation have been conducted. Regarding the onsite investigation findings, visual evidence of NAPL was observed in three upland locations and in adjacent hydric soils and sediment, but NAPL accumulation has only been observed in one onsite well. Soil analytical data suggests concentrations of extractable and volatile petroleum hydrocarbons, PAHs, volatile organic compounds (VOCs), and inorganic constituents above applicable soil standards. Groundwater analytical data suggests minor exceedances of applicable groundwater standards for two PAHs, one VOC, and numerous exceedances for physiologically available cyanide. A jewelry manufacturer was located upgradient of the property and has documented chlorinated VOC impacts at its property and extending onto NEGC property. In addition, the documented use of cyanide at the former jewelry manufacturer may be a source of cyanide impacts at the site. Risk assessments to evaluate risk of harm to human health, safety, public welfare, and the environment require additional site investigation and response actions to reach conclusions of no significant risk. The preliminary Phase III report proposed remedial objectives for the following: reduce NAPL thickness to less than half an inch; eliminate direct contact with NAPL and impacted surface and subsurface soil, and sediments; eliminate potential risk posed by NAPL-impacted sediment in adjacent river; eliminate potential sources of impacts; remove a rusted drum; and if feasible, achieve background conditions. The report further states that the selection of final remedial alternatives remains premature until the overall site investigation is completed and issues regarding site responsibility are further developed.

66 Fifth Street, Fall River, Massachusetts Site - In a letter dated March 11, 2003, MADEP provided NEGC with a Notice of Responsibility for 66 Fifth Street in Fall River, Massachusetts. This Notice of Responsibility requested that site assessment activities be conducted at the former MGP at 66 Fifth Street to determine whether or not there was a release of cyanide into the groundwater at this site that impacted downgradient properties at 60 and 82 Hartwell Street. NEGC submitted an IRA Work Plan in May 2003. IRA Status Reports have been submitted every six months beginning in July 2003, culminating in an IRA Completion Report submitted in July 2005 that concluded neither an imminent hazard nor a critical exposure pathway exist at the site. A Phase 1/Tier Classification was submitted in March 2004. Investigation work performed to date indicates that cyanide concentrations at the downgradient properties are unrelated to the NEGC property at 66 Fifth Street. As required by MADEP, NEGC will submit a Phase II Comprehensive Site Assessment, including a Risk Assessment by March 2006. The Company believes that it is

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likely that no further action will be necessary on this site.

State Avenue, Fall River, Massachusetts Site - The Company received a Notice of Responsibility, Request for Information and Request for Immediate Response Action Plan dated July 1, 2004, for an area in Fall River, Massachusetts along State Avenue (State Avenue Area) that is contiguous to the Bay Street Area of Rhode Island. In response to this Notice from MADEP, the Company submitted an IRA Plan to MADEP on July 26, 2004. MADEP verbally approved the IRA Plan and the investigation was completed in early 2005. IRA Status Reports were submitted to MADEP on November 1, 2004 and May 5, 2005. The Company submitted an IRA Completion and Response Action Outcome Report on June 30, 2005 indicating that no further action is required.

Charles Street, Fall River, Massachusetts Site - The Company received a verbal request from MADEP in 2004 to investigate a suspected spill of #2 and/or #6 fuel oil observed during utility work in a road adjacent to the site. NEGC submitted a letter to MADEP on January 3, 2005 stating its intention to investigate the site and provided an investigation work plan. The voluntary site investigation was conducted in May 2005 and the results of the investigation are being compiled in a report due to MADEP on November 10, 2005.

Valley Resources Sites in Rhode Island and Massachusetts -Valley Gas Company (acquired in September 2000 by the Company) is a party to an action in which Blackstone Valley Electric Company (Blackstone) brought suit for contribution to its expenses of cleanup of a site on Mendon Road in Attleboro, Massachusetts, to which coal gas manufacturing waste was transported from a former MGP site in Pawtucket, Rhode Island (Blackstone Litigation). Valley Gas Company takes the position in that litigation that it is indemnified for any cleanup expenses by Blackstone pursuant to a 1961 agreement signed at the time of Valley Gas Company’s creation. This suit was stayed in 1995 pending the issuance of rulemaking at the U.S. Environmental Protection Agency (the U.S. EPA). The requested rulemaking concerned whether ferric ferrocyanide (FFC) is among the “cyanides” listed as toxic substances under the Clean Water Act and, therefore, is a “hazardous substance” under the Comprehensive Environmental Response, Compensation and Liability Act. On October 6, 2003, the U.S. EPA issued a Final Administrative Determination declaring that FFC is one of the cyanides under the environmental statutes. While the Blackstone Litigation was stayed, Valley Gas Company and Blackstone (which merged in May 2000 with Narragansett Electric Company, a subsidiary of National Grid) have received letters of responsibility from RIDEM with respect to releases from two MGP sites in Rhode Island. RIDEM issued letters of responsibility to Valley Gas Company and Blackstone in September 1995 for the Tidewater MGP in Pawtucket, Rhode Island, and in February 1997 for the Hamlet Avenue MGP in Woonsocket, Rhode Island. Valley Gas Company entered into an agreement with Blackstone (now Narragansett, a subsidiary of National Grid) in which Valley Gas Company and Blackstone agreed to share equally the costs associated with the Tidewater site subject to reallocation upon final determination of the legal issues that exist between the companies with respect to responsibility for expenses for the Tidewater site and otherwise. No such agreement has been reached with respect to the Hamlet site.

While the Blackstone Litigation has been stayed, National Grid and the Company have jointly pursued claims against the bankrupt Stone & Webster entities (Stone & Webster) based upon Stone & Webster’s historic management of MGP facilities on behalf of the alleged predecessors of both companies. On January 9, 2004, the U.S. Bankruptcy Court for the District of Delaware issued an order approving a settlement among National Grid, the Company and Stone & Webster that provided for the payment of $5,000,000 out of the bankruptcy estates. This settlement resulted in a payment of $1,250,000 to the Company for payment of environmental costs associated with the former Fall River Gas Company, and a $3,750,000 payment to the Company and National Grid jointly for future environmental costs at the Tidewater and Hamlet sites. The settlement further provides an admission of liability by Stone & Webster that gives National Grid and the Company additional rights against historic Stone & Webster insurers.

In August and September of 2003, representatives of the Company and National Grid, parent company of Narragansett Electric Company, conducted meetings to discuss the possibility of a negotiated settlement between the two companies. Settlement discussions are ongoing.

Mercury Release - The Company has completed an investigation of an incident involving the release of mercury stored in an NEGC facility in Pawtucket, Rhode Island. On October 19, 2004, New England Gas Company discovered that an NEGC facility had been broken into and that mercury had been spilled both inside a building and in

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the immediate vicinity. Mercury had also been removed from the Pawtucket facility and a quantity had been spilled in a parking lot in the neighborhood. Mercury from the parking lot spill was apparently tracked into some nearby apartment units, as well as some other buildings. Spill cleanup has been completed at the NEGC property and nearby apartment units. Investigation of some other neighborhood properties has been undertaken, with cleanup necessitated in a few instances. State and federal authorities are also investigating the incident and have arrested the alleged vandals of the Pawtucket facility. In addition, they are conducting inquiries regarding NEGC's compliance with relevant environmental requirements, including hazardous waste management provisions, spill and release notification procedures, and hazard communication requirements. NEGC has received a subpoena requesting documents relating to this matter. The Company believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

Mercury Refining Superfund Site - By letter dated October 26, 2005, Providence Gas received a notice of potential liability from U.S. EPA Region II for the Mercury Refining Superfund Site located in the towns of Colonie and Guilderland, Albany County, New York. The notice invites the Company to enter into an administrative settlement agreement as a small or “de minimis” party with the U.S. EPA within 45 days of the date of the notice and make a payment of approximately $50,000.

PG Energy.

Pennsylvania Sites - During 2002, PG Energy received inquiries from the Pennsylvania Department of Environmental Protection (PADEP) pertaining to three former MGP sites located in Scranton, Bloomsburg and Carbondale, Pennsylvania. At the request of PADEP, PG Energy is currently performing environmental assessment work at the Scranton MGP site. In March 2004, PG Energy filed an Initial Site Assessment Characterization Report on the Scranton site and is preparing to submit a Comprehensive Site Assessment Characterization Work Plan for further assessment of this site.

PG Energy has participated financially in PPL Electric Utilities Corporation’s (PPL) environmental and health assessment of an additional MGP site located in Sunbury, Pennsylvania. In May 2003, PPL commenced a remediation project at the Sunbury site that was completed in August 2003. PG Energy has contributed to PPL’s remediation project by making cash payments and by removing and relocating gas utility lines located in the path of the remediation. In a letter dated January 12, 2004, PADEP notified PPL of its approval of the Remedy Certification Report submitted by PPL for the Sunbury MGP cleanup project.

On March 31, 2004, PG Energy entered into a Voluntary Consent Order and Agreement (Multi-Site Agreement) with PADEP. This Multi-Site Agreement is for the purpose of developing and implementing an environmental assessment and remediation program for five MGP sites (including the Scranton, Bloomsburg, Wilkes-Barre, Nanticoke and Carbondale sites) and six MGP holder sites owned by PG Energy in the State of Pennsylvania. Under the Multi-Site Agreement, PG Energy is to perform environmental assessments of these sites within two years of the effective date of the Multi-Site Agreement. Currently, PG Energy is performing the environmental assessments of these sites. Thereafter, PG Energy may be required to perform additional assessment and remediation activity as such assessment or remediation activity is deemed necessary based upon the results of the initial assessments.

Panhandle Energy Environmental Matters.

Gas Transmission Systems - Panhandle Energy’s gas transmission operations are subject to federal, state and local regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. Panhandle Energy has previously identified environmental contamination at certain sites on its gas transmission systems and has undertaken cleanup programs at these sites. The contamination resulted from the past use of lubricants containing polychlorinated biphenyls (PCBs) in compressed air systems; the past use of paints containing PCBs; and the prior use of wastewater collection facilities and other on-site disposal areas. Panhandle Energy has developed and is implementing a program to remediate such contamination in accordance with federal, state and local regulations.

As part of the cleanup program resulting from contamination due to the use of lubricants containing PCBs in

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compressed air systems, Panhandle Eastern Pipe Line and Trunkline have identified PCB levels above acceptable levels inside the auxiliary buildings that house the air compressor equipment at thirty-three compressor station sites. Panhandle Energy has developed and is implementing a process approved by the U.S. EPA to remediate this PCB contamination in accordance with applicable federal, state and local regulations. Sixteen sites have been decontaminated in accordance with such process.

At some locations, PCBs have been identified in paint that was applied many years ago. In accordance with U.S. EPA regulations, Panhandle Energy has implemented a program to remediate sites where such issues are identified during painting activities. If PCBs are identified above acceptable levels, the paint is removed and disposed of in a U.S. EPA-approved manner.

The Illinois Environmental Protection Agency (the Illinois EPA) notified Panhandle Eastern Pipe Line and Trunkline, together with other non-affiliated parties, of contamination at three former waste oil disposal sites in Illinois. Panhandle Eastern Pipe Line’s and Trunkline’s estimated share for the costs of assessment and remediation of the sites, based on the volume of waste sent to the facilities, is approximately 17%. Panhandle Eastern Pipe Line and Trunkline and twenty-one other non-affiliated parties conducted an initial voluntary investigation of the Pierce Oil Springfield site, one of the three sites. In addition, Illinois EPA has informally indicated that it has referred the Pierce Oil Springfield site to the U.S. EPA so that environmental contamination present at the site can be addressed through the federal Superfund program. No formal notice has yet been received from either agency concerning the referral. However, the U.S. EPA is expected to issue special notice letters and has begun the process of listing the site on the National Priority List. Panhandle Eastern Pipe Line and Trunkline and three of the other non-affiliated parties associated with the Pierce Oil Springfield site met with the U.S. EPA and Illinois EPA regarding this issue. Panhandle Eastern Pipe Line and Trunkline were given no indication as to when the listing process was to be completed. Panhandle Eastern Pipe Line and Trunkline have also submitted their response to a Comprehensive Environmental Response, Compensation, and Liability Act 104e data request from U.S. EPA Region V regarding a second Pierce Waste Oil site known as the Dunavan site, located in Oakwood, Illinois. By letter dated September 30, 2005, Panhandle Eastern Pipe Line and Trunkline along with numerous other non-affiliated parties received notices of potential liability from U.S. EPA Region V for the Dunavan site. The notice demands reimbursement to the U.S. EPA for its costs incurred to date in the amount of approximately $1,800,000 and encourages each potentially responsible party (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 U.S. EPA held an initial settlement conference with all PRPs on October 26, 2005.

On June 16, 2005, Panhandle Eastern Pipe Line 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, initially reported as 45 gallons, of hydrocarbons reached the Mississippi River. Panhandle Eastern Pipe Line 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. Panhandle Eastern Pipe Line is in the process of resolving potential claims of affected boat owners and the marina operator. By letter dated August 12, 2005 Panhandle Eastern Pipe Line received a violation notice from the Illinois EPA alleging that Panhandle Eastern Pipe Line is in apparent violation of several sections of the Illinois Environmental Protection Act by allowing the release. The violation notice did not propose a penalty.  An extensive response to the violation notice was submitted on September 30, 2005. A conference call was held between Illinois EPA and Panhandle representatives on October 20, 2005 to discuss the response. Panhandle Eastern Pipe Line has agreed to provide additional information by November 10, 2005. The Company does not believe the outcome of this matter will have a material adverse effect on its financial position, results of operations or cash flows.

Based on information available at this time, and the reviews undertaken by the Company to identify potential exposure, the Company believes the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.

Air Quality Control - In 1998, the U.S. EPA issued a final rule on regional ozone control that requires Panhandle Energy to place controls on engines in five Midwestern states. The part of the rule that affects Panhandle Energy was

26

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

challenged in court by various states, industry and other interests, including the Interstate Natural Gas Association of America (INGAA), an industry group to which Panhandle Energy belongs. In March 2000, the court upheld most aspects of the U.S. EPA rule, but agreed with INGAA’s position and remanded to the U.S. EPA the sections of the rule that affected Panhandle Energy. The final rule was promulgated by the U.S. EPA in April 2004. The five Midwestern states have not promulgated state regulations to address the requirements of this rule. Based on a U.S. EPA guidance document negotiated with gas industry representatives in 2002, it is believed that Panhandle Energy will be required under state rules to reduce nitrogen oxide (NOx) emissions by 82% on the identified large internal combustion engines and will be able to trade off engines within the company and within each of the five Midwestern states affected by the rule in an effort to create a cost effective NOx reduction solution. The final implementation date is May 2007. The rule affects twenty large internal combustion engines on the Panhandle Energy system in Illinois and Indiana at an approximate cost of $23,000,000 for capital improvements through 2007, based on current projections.

The Illinois EPA has distributed several draft versions of a rule to control NOx emissions from reciprocating engines and turbines state-wide. The latest draft requires controls on engines regulated under the EPA NOx SIP Call by May 1, 2007 and the remaining engines by January 1, 2009. The state is requiring the controls to comply with U.S. EPA rules regarding the NOx SIP Call, ozone non-attainment and fine particulate standards. The agency has held multiple meetings with industry representatives to discuss the draft rule and is expected to propose the rule this fall. The rule is currently being reviewed for potential impact to Panhandle Energy. As drafted, the rule applies to all Panhandle Eastern Pipe Line and Trunkline stations in Illinois and significant expenditures would be required for emission control.

In 2002, the Texas Commission on Environmental Quality enacted the Houston/Galveston SIP regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and requires the installation of emission controls. New regulations also require certain grandfathered facilities in Texas to enter into the new source permit program which may require the installation of emission controls at one additional facility owned by Panhandle Energy. These two rules affect two company facilities in Texas at an estimated cost of approximately $14,000,000 for capital improvements through March 2007, based on current projections.

The U.S. EPA promulgated various Maximum Achievable Control Technology rules in February 2004. The rules require that Panhandle Eastern Pipe Line and Trunkline control Hazardous Air Pollutants (HAPs) emitted from certain internal combustion engines at major HAPs sources. Most Panhandle Eastern Pipe Line and Trunkline compressor stations are major HAPs sources. The HAPs pollutant of concern for Panhandle Eastern Pipe Line and Trunkline is formaldehyde. As promulgated, the rule seeks to reduce formaldehyde emissions by 76% from these engines. Catalytic controls will be required to reduce emissions under these rules with a final implementation date of June 2007. Panhandle Eastern Pipe Line and Trunkline have over twenty internal combustion engines subject to the rules. It is expected that compliance with these regulations will necessitate an estimated expenditure of $1,000,000 for capital improvements, based on current projections.

Regulatory.

Through filings made on various dates, the staff of the MPSC has recommended that the MPSC disallow a total of approximately $38,500,000 in gas costs incurred during the period July 1, 1997 through June 30, 2003. The basis of $32,100,000 of the total proposed disallowance is disputed by MGE and appears to be the same as was rejected by the Commission through an order dated March 12, 2002, applicable to the period July 1, 1996 through June 30, 1997; no date for a hearing in this matter has been set. The basis of $3,000,000 of the total proposed disallowance, applicable to the period July 1, 2000 through June 30, 2001, is disputed by MGE, was the subject of a hearing concluded in November 2003 and is presently awaiting decision by the MPSC. The basis of $3,400,000 of the total proposed disallowance, applicable to the period July 1, 2001 through June 30, 2003, is disputed by MGE; a hearing in this matter has been set for April 2006.

Southwest Gas Litigation.

During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire

27

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwest Gas Corporation (Southwest). All of these actions eventually were transferred to the U.S. District Court for the District of Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of summary judgments granted, there were no claims allowed against the Company. 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 $60,000,000 in punitive damages against former Commissioner Irvin. After the District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages, former Commissioner Irvin appealed to the Ninth Circuit Court of Appeals (Ninth Circuit). On July 25, 2005, the Ninth Circuit denied former Commissioner Irvin’s motions to set aside the verdict and affirmed the judgment against him for compensatory damages. The Ninth Circuit also determined that punitive damages against former Commissioner Irvin were appropriate but found that the $60,000,000 punitive damage award against him was excessive. Accordingly, the Ninth Circuit remanded that issue to the District Court for further action. 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 whether the Company ultimately will collect such amounts.

Other.

In 1993, the U.S. Department of the Interior announced its intention to seek, through its Minerals Management Service (the MMS), additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements, buyouts, and buy downs of gas sales contracts with natural gas pipelines. The Company’s former exploration and production subsidiary, Southern Union Exploration Company (SX), received a final determination by an area office of the MMS that it is obligated to pay additional royalties on proceeds realized by SX as a result of a previous settlement between SX and Public Service Company of New Mexico. This claim was appealed to the Director of the MMS, which stayed the requirement that SX pay the claim pending the outcome of the appeal. In August 2005, the Associate Deputy Secretary of the MMS issued an order accepting most of SX’s appellate arguments, but finding that SX still owed additional royalties in the amount of $293,000 plus interest in the amount of $650,000. The company is currently reviewing its options with respect to the order. The MMS Royalty Valuation Chief also issued to SX an Order to Perform Major Portion Pricing and Dual Accounting on SX’s leases for the period from 1984 until 1995. The Company believes that it has several defenses to the Order to Perform, and has appealed it to the Director of the MMS. The amounts that may be claimed have yet to be fully quantified, and the Order to Perform has been stayed pending the outcome of the appeal. The Company believes the outcome of these matters will not have a material adverse effect on its financial position, results of operations or cash flows.

Additionally, with respect to certain producer contract settlements, Panhandle Eastern Pipe Line and Trunkline may be contractually required to reimburse producers for or, in some instances, indemnify them against, the MMS 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 that are likely to take substantial time to resolve. If required to reimburse or indemnify the producers, Panhandle Energy's pipelines may file with FERC to recover a portion of these costs from pipeline customers. Panhandle Energy believes the outcome of this matter will not have a material adverse effect on its financial position, results of operations or cash flows.

Jack Grynberg, an individual, has filed actions against a number of companies, including Panhandle Energy, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On May 13, 2005, the Special Master in this case issued a recommended decision that would, if adopted by the District Judge, result in dismissal of Panhandle Energy and its affiliates from the case. A similar action, known as the Will Price litigation, has also been filed against a number of companies, including Panhandle Energy, in Kansas District Court. Panhandle Energy is currently awaiting the decision of the trial judge on the defendants’ motion to dismiss the Will Price action. Panhandle Energy believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which was filed with and approved by FERC. As a result, Panhandle Energy believes that it has meritorious defenses to the complaint (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Panhandle Energy complied with the terms of its tariff) and is defending the suits vigorously.

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southern Union and its subsidiaries are parties to other legal proceedings that management considers to be normal actions to which an enterprise of its size and nature might be subject. Management does not consider these actions to be material to Southern Union's overall business or financial condition, results of operations or cash flows.

Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast after coming through the Gulf of Mexico. These hurricanes caused modest damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG, the ultimate cost of which cannot yet be accurately predicted. However, based on the preliminary damage assessments which are underway, management believes that there will be future revenue, expense, and capital impacts of Hurricanes Rita and Katrina in 2005 and 2006, primarily on Sea Robin and Trunkline LNG. For 2005 and 2006, the Company estimates revenue losses of approximately $11,000,000 to $13,000,000, expense increases of up to $5,000,000, and additional capital outlays of approximately $14,000,000 to $18,000,000. Estimated expenses and capital outlays primarily include repair and replacement of equipment lost or damaged in the hurricanes, potential abandonment costs for certain facilities, which will be impacted by producer decisions regarding rebuilding their damaged platforms and reconnecting their gas reserves to Panhandle Energy’s pipelines, higher insurance premiums, higher LNG construction costs, as well as employee assistance related expenses. The revenue losses expected relate primarily to reduced volumes on Sea Robin into 2006 and some delays in the completion of Trunkline LNG’s Phase I and Phase II expansions which are currently anticipated.  Trunkline LNG and the contractor on the LNG project are currently engaged in active discussions to reach resolution on revised project timing and additional costs to the respective parties associated with the hurricane impacts.  The Company currently expects the delays to be eight weeks and five weeks for Phase I and Phase II, respectively. No significant expenditures had occurred nor accruals been made with respect to either hurricane as of September 30, 2005. Additionally, the Company anticipates reimbursement from its property insurance carrier for damages from Hurricane Rita in excess of its $5,000,000 deductible. However, such reimbursement could be further limited depending on the magnitude of the claims made to the carrier by all of its covered parties for Hurricane Rita, due to its $1 billion cap on total payout per incident. Based on the information available at this time, management does not expect the ultimate impact of the damages caused by these two hurricanes to have a material adverse impact on the Company.

XV. Subsequent Events

On November 8, 2005, the Company announced that Thomas F. Karam, a Director and President and Chief Operating Officer of the Company, resigned from his positions with the Company and its subsidiaries, divisions, joint ventures and other affiliates, effective immediately. In connection with Mr. Karam's departure, on November 7, 2005, the Company and Mr. Karam entered into a Separation Agreement and General Release (the Agreement). Pursuant to the Agreement, which supersedes the terms and conditions of Mr. Karam's employment agreement, Mr. Karam will receive certain severance, bonus and non-competition payments as well as certain other distributions and reimbursements. The Company expects to record a $3,712,000 fourth quarter charge related to the severance and bonus payments under the Agreement and to amortize the $540,000 payment for the non-competition arrangements over its two-year term. Mr. Karam will also repay a promissory note in favor of Southern Union, which has an outstanding principal balance of $2,383,000. In addition, Mr. Karam will provide consulting services to the Company for a period of two years commencing January 2006.

Effective upon Mr. Karam's resignation, the Board of Directors of the Company appointed George L. Lindemann, Chairman and Chief Executive Officer of the Company, to the office of President. In recognition of the additional responsibilities to be assumed by Mr. Lindemann, the Compensation Committee of the Board of Directors also authorized an increase in Mr. Lindemann's annual base salary from $925,000 to $1,500,000.

29

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

XVI. Reportable Segments

The Company’s operating segments are aggregated into reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. The Company operates in two reportable segments. The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through the Company’s three regulated utility divisions: MGE, PG Energy and NEGC. The Transportation and Storage segment is primarily engaged in the interstate transportation and storage of natural gas in the Midwest and Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and the Company’s equity investment in CCE Holdings.

Revenue included in the All Other category is attributable to several operating subsidiaries of the Company: PEI Power Corporation generates and sells electricity; PG Energy Services Inc. offers appliance service contracts; and New England Appliance Company rents natural gas appliances. None of these businesses meet or have ever met the quantitative thresholds for determining reportable segments individually or in the aggregate. The Company also has corporate operations that do not generate any revenues.

The Company evaluates segment performance based on several factors, of which the primary financial measure, beginning January 1, 2005, is earnings before interest and taxes (EBIT). As a result of the Company’s investment in CCE Holdings in November 2004, the operating results of which are included in earnings from unconsolidated investments, EBIT allows management and investors to more effectively evaluate the performance of all of the Company’s consolidated subsidiaries and unconsolidated investments. Evaluating segment performance based on EBIT is a change from utilizing operating income in prior periods. Accordingly, prior period segment performance information has been conformed to the current period presentation. The Company defines EBIT as net earnings (loss) applicable to common shareholders, adjusted for: (i) items that do not impact earnings (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes; (ii) income taxes; (iii) interest; and (iv) dividends on preferred stock. EBIT may not be comparable to measures used by other companies. Additionally, EBIT 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 months ended September 30, 2005 and 2004.

The following table sets forth certain selected financial information for the Company’s segments and a reconciliation of EBIT to net earnings for the three and nine months ended September 30, 2005 and 2004.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005			2004		2005		2004
Revenues from external customers:
Distribution	$	137,000		$	124,021	$	960,953	$	936,575
Transportation and Storage		115,945			109,264		361,766		355,684
Total segment operating revenues		252,945			233,285		1,322,719		1,292,259
All Other		2,102			1,237		5,049		3,630
Total consolidated operating revenues	$	255,047		$	234,522	$	1,327,768	$	1,295,889
Depreciation and amortization:
Distribution	$	15,671		$	15,071	$	47,433	$	43,409
Transportation and Storage (1)		15,145			15,178		45,537		42,009
Total segment depreciation and amortization		30,816			30,249		92,970		85,418
All Other		148			150		453		432
Corporate		(560	)		194		245		467
Total consolidated depreciation and amortization	$	30,404		$	30,593	$	93,668	$	86,317

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SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Earnings (loss) from unconsolidated investments:
Distribution	$	--		$	--		$	--		$	--
Transportation and Storage		21,916			54			57,569			154
Total segment earnings from unconsolidated investments		21,916			54			57,569			154
All Other		256			(12	)		176			(35	)
Total consolidated earnings from unconsolidated investments	$	22,172		$	42		$	57,745		$	119
Other income (expense):
Distribution	$	(568	)	$	497		$	(491	)	$	1,367
Transportation and Storage		72			446			1,387			716
Total segment other income (expense), net		(496	)		943			896			2,083
All Other		69			601			1,170			2,045
Corporate		(1,030	)		(1,163	)		(7,100	)		(2,576	)
Total consolidated other income (expense), net	$	(1,457	)	$	381		$	(5,034	)	$	1,552
Segment performance:
Distribution EBIT	$	(2,359	)	$	(17,599	)	$	81,360		$	69,249
Transportation and Storage EBIT		68,097			38,417			207,974			141,868
Total segment EBIT		65,738			20,818			289,334			211,117
All Other		786			507			1,885			(849	)
Corporate		(5,520	)		(2,162	)		(11,561	)		(3,786	)
Interest		(33,184	)		(30,618	)		(100,185	)		(91,886	)
Federal and state income taxes		(8,230	)		4,315			(52,012	)		(42,426	)
Net earnings (loss)	$	19,590		$	(7,140	)	$	127,461		$	72,170
Expenditures for long-lived assets:
Distribution	$	28,559		$	21,192		$	61,587		$	58,191
Transportation and Storage		54,023			50,960			150,161			118,982
Total segment expenditures for long-lived assets		82,582			72,152			211,748			177,173
All Other		224			130			880			700
Corporate		(6,413	)		5,059			(703	)		14,430
Total consolidated expenditures for long-lived assets	$	76,393		$	77,341		$	211,925		$	192,303

	September 30,		December 31,
	2005		2004
Total assets:
Distribution	$	2,428,286	$	2,448,750
Transportation and Storage		3,069,668		2,957,880
Total segment assets		5,497,954		5,406,630
All Other		39,174		40,319
Corporate		137,134		121,340
Total consolidated assets	$	5,674,262	$	5,568,289

(1) Depreciation and amortization reflected herein for the nine months ended September 30, 2004 is $3,193,000 less than that reported by Panhandle Energy in its separate SEC filing for the same period. The outside appraisals for the Panhandle Energy assets acquired and liabilities assumed were finalized after Southern Union had filed its Form 10-Q for the quarter ended December 31, 2003, but prior to Panhandle Energy filing its Form 10-K for the year ended December 31, 2003. Panhandle Energy was able to reflect depreciation and amortization expense consistent with the final outside appraisals as of December 31, 2003, which Southern Union recognized during the quarter ended March 31, 2004.

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

Introduction

Management’s Discussion and Analysis of Results of Operations and Financial Condition is provided as a supplement to the accompanying unaudited interim consolidated financial statements and notes to help provide an understanding of the financial condition, changes in financial condition and results of operations of Southern Union Company (Southern Union or the Company). 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 Southern Union’s results of operations on a consolidated basis and on a segment basis for each reportable segment, information relating to the Company’s liquidity and capital resources, and quantitative and qualitative disclosures about market risk and other matters.

Overview

Southern Union owns and operates assets in the regulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. Through Southern Union’s wholly-owned subsidiary, Panhandle Eastern Pipe Line Company, LP, and its subsidiaries (hereafter collectively referred to as Panhandle Energy), the Company owns and operates more than 10,000 miles of interstate pipelines that transport up to 5.4 billion cubic feet per day (Bcf/d) 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 Energy also owns and operates a liquefied natural gas (LNG) import terminal, located on Louisiana’s Gulf Coast, which is one of the largest operating LNG facilities in North America. Through its investment in CCE Holdings, LLC (CCE Holdings), Southern Union has an interest in and operates the Transwestern Pipeline (Transwestern) and Florida Gas Transmission Company (FGT) interstate pipelines, comprising more than 7,400 miles of interstate pipelines that transport up to approximately 4.1 Bcf/d of natural gas, which stretch from western Texas and the San Juan Basin to markets throughout the Southwest and to California, and from the Gulf Coast to Florida. Through Southern Union’s three regulated utility divisions - Missouri Gas Energy (MGE), PG Energy and New England Gas Company (NEGC) - the Company serves approximately 950,000 natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island.

On November 17, 2004, CCE Holdings, LLC (CCE Holdings), a joint venture in which Southern Union indirectly owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy, LLC (CrossCountry Energy) from Enron Corp. and its subsidiaries for a purchase price of approximately $2,450,000,000 in cash, including certain consolidated debt. Concurrent with this transaction, CCE Holdings divested CrossCountry Energy’s interests in Northern Plains Natural Gas Company, LLC and NBP Services, LLC to ONEOK, Inc. (ONEOK) for $175,000,000 in cash. Following these transactions, CCE Holdings owns 100% of Transwestern Pipeline Company, LLC and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of Florida Gas Transmission Company. An affiliate of El Paso Corporation owns the remaining 50% of Citrus. The Company funded its $590,500,000 equity investment in CCE Holdings through borrowings of $407,000,000 under an equity bridge loan facility, net proceeds of $142,000,000 from the settlement on November 16, 2004 of its July 2004 forward sale of 8,242,500 shares of its common stock, and additional borrowings of approximately $42,000,000 under its existing revolving credit facility. Subsequently, in February 2005 Southern Union issued 2,000,000 of its 5% Equity Units from which it received net proceeds of approximately $97,378,000, and issued 14,913,042 shares of its common stock, from which it received net proceeds of approximately $331,772,000, all of which was utilized to repay indebtedness incurred in connection with its investment in CCE Holdings (see Note VII - Stockholders’ Equity). The Company’s investment in CCE Holdings is accounted for using the equity method of accounting. Accordingly, Southern Union reports its share of CCE Holdings’ earnings as earnings from unconsolidated investments in the Consolidated Statement of Operations.

Results of Operations

The Company’s results of operations are discussed on a consolidated basis and on a segment basis for each of the two reportable segments: the Distribution segment and the Transportation and Storage segment. Beginning January 1, 2005, segment results of operations are presented on the basis of earnings before interest and taxes (EBIT), which

32

is the primary performance measure that the Company uses to internally manage its business. Evaluating segment performance based on EBIT is a change from utilizing operating income in prior periods. Accordingly, prior period segment performance information has been conformed to the current period presentation. For additional information as to segment reporting and the calculation of EBIT, see Note XVI - Reportable Segments.

Consolidated Results

The following table provides selected financial information regarding the Company’s consolidated results of operations and a reconciliation of EBIT to net earnings (loss) for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(thousands of dollars)						(thousands of dollars)
EBIT:
Distribution segment	$	$ (2,359	)	$	(17,599	)	$	81,360		$	69,249
Transportation and storage segment		68,097			38,417			207,974			141,868
All other		786			507			1,885			(849	)
Corporate		(5,520	)		(2,162	)		(11,561	)		(3,786	)
Total EBIT		61,004			19,163			279,658			206,482
Interest		(33,184	)		(30,618	)		(100,185	)		(91,886	)
Earnings (loss) before income taxes		27,820			(11,455	)		179,473			114,596
Federal and state income taxes (benefit)		8,230			(4,315	)		52,012			42,426
Net earnings (loss)		19,590			(7,140	)		127,461			72,170
Preferred stock dividends		(4,341	)		(4,341	)		(13,023	)		(13,023	)
Net earnings (loss) applicable to common shareholders	$	$ 15,249		$	(11,481	)	$	114,438		$	59,147

Consolidated Results - Three Months Ended September 30, 2005 Compared to 2004. The Company recorded net earnings applicable to common shareholders of $15,249,000 ($.13 per diluted share, hereinafter referred to as per share) for the three months ended September 30, 2005 compared with an $11,481,000 net loss ($.14 loss per share) for the same period in 2004. The $26,730,000 increase in net earnings applicable to common shareholders was primarily due to the following:

·   a $15,240,000 increase in EBIT from the Distribution segment (see Business Segment Results - Distribution Segment);

·   a $29,680,000 increase in EBIT from the Transportation and Storage segment (see Business Segment Results - Transportation and Storage Segment); and

·   a $279,000 increase in EBIT from subsidiary operations included in the All Other category.

The above items were partially offset by the following:

·   a $3,358,000 decrease in EBIT from Corporate operations (see Corporate);

·   a $2,566,000 increase in interest expense (see Interest Expense); and

·   a $12,545,000 increase in income tax expense (see Federal and State Income Taxes).

Consolidated Results - Nine Months Ended September 30, 2005 Compared to 2004. The Company recorded net earnings applicable to common shareholders of $114,438,000 ($1.02 per share) for the nine months ended September 30, 2005 compared with $59,147,000 ($.71 per share) for the same period in 2004. The $55,291,000 increase in net earnings applicable to common shareholders was primarily due to the following:

·   a $12,111,000 increase in EBIT from the Distribution segment (see Business Segment Results - Distribution Segment);

33

·   a $66,106,000 increase in EBIT from the Transportation and Storage segment (see Business Segment Results - Transportation and Storage Segment); and

·   a $2,734,000 increase in EBIT from subsidiary operations included in the All Other category (see All Other Operations).

The above items were partially offset by the following:

·   a $7,775,000 decrease in EBIT from Corporate operations (see Corporate);

·   an $8,299,000 increase in interest expense (see Interest Expense); and

·   a $9,586,000 increase in income tax expense (see Federal and State Income Taxes).

All Other Operations. EBIT from subsidiary operations included in the All Other category for the nine months ended September 30, 2005 increased by $2,734,000 to $1,885,000. The increase in EBIT primarily reflects a $2,985,000 charge recorded by PEI Power Corporation during the first quarter of 2004 to provide for the estimated future debt service payments in excess of projected tax revenues for the tax incremental financing obtained for the development of PEI Power Park.

Corporate.EBIT from Corporate operations for the three months ended September 30, 2005 decreased by $3,358,000 to a loss of $5,520,000. The decrease in Corporate EBIT reflects the impact of $3,848,000 of non-cash compensation expense recorded upon the separation of two former Southern Union executives (see Note VII - Stockholders' Equity) and increased outside accounting, consulting and legal fees relating to Sarbanes-Oxley 404 compliance and other corporate matters, partially offset by decreased benefit costs.

EBIT from Corporate operations for the nine months ended September 30, 2005 decreased by $7,775,000 to a loss of $11,561,000. The decrease in Corporate EBIT reflects the impact of $4,508,000 recorded during the first quarter of 2005 to reserve for an other-than-temporary impairment of the Company’s investment in Advent and to record a liability for the guarantee by a subsidiary of the Company of a line of credit between Advent and a bank, $3,848,000 of non-cash compensation expense, previously discussed, and $3,128,000 of increased pension expense (including a $1,335,000 curtailment loss from plan termination and a $1,141,000 curtailment loss on pension plan payments to a former executive of the Company, recorded during the first quarter of 2005). These increases were partially offset by a decrease in taxes other than on income and revenues due to a $1,500,000 charge recorded during the second quarter of 2004 to provide for the Company’s estimated liability under a sales and use tax audit and decreased payroll and benefit costs.

Interest Expense. Total interest expense for the three months ended September 30, 2005 increased by $2,566,000, or 8%, to $33,184,000. The increase was primarily attributable to $2,301,000 of increased interest expense on short-term debt as discussed below and $1,094,000 of interest expense recorded in 2005 related to the Company’s 4.375% senior notes (see Note VII - Stockholders’ Equity). These increases were partially offset by decreased interest expense of $721,000 on the Company’s $311,087,000 bank note (the 2002 Term Note) and lower interest expense on Panhandle Energy’s debt of $80,000 (net of amortization of debt premiums established in purchase accounting related to the Panhandle Energy acquisition). The average rate of interest on all debt increased from 5.28% for the three months ended September 30, 2004 to 5.55% for the same period in 2005.

Interest expense on short-term debt for the three months ended September 30, 2005 increased by $2,301,000 to $2,739,000, primarily due to the increase in the average amount of short-term debt outstanding from $49,800,000 during 2004 to $167,900,000 during 2005 and the increase in the average rate of interest on short-term debt from 2.6% in 2004 to 4.5% in 2005.

Total interest expense for the nine months ended September 30, 2005 increased by $8,299,000, or 9%, to $100,185,000. The increase was primarily attributable to $4,234,000 of increased interest expense on short-term debt as discussed below, $3,113,000 of interest expense recorded during the first quarter of 2005 related to the $407,000,000 bridge loan (see Note X - Notes Payable) that was used to finance a portion of the Company’s investment in CCE Holdings and $2,759,000 of increased interest expense recorded in 2005 related to the Company’s 4.375% senior notes. These increases were partially offset by decreased interest expense of $1,212,000 on the 2002 Term Note and lower interest expense on Panhandle Energy’s debt of $912,000 (net of amortization of debt premiums

34

established in purchase accounting related to the Panhandle Energy acquisition). The average rate of interest on all debt was 5.03% during the nine months ended September 30, 2005 and 2004.

Interest expense on short-term debt for the nine months ended September 30, 2005 increased by $4,234,000 to $5,601,000, primarily due to the increase in the average amount of short-term debt outstanding from $73,900,000 during 2004 to $153,707,000 during 2005 and the increase in the average rate of interest on short-term debt from 2.1% in 2004 to 3.8% in 2005.

Federal and State Income Taxes. The Company's estimated annual consolidated federal and state effective income tax rate (Estimated EITR) for 2005 is 29% as of September 30, 2005. The Company’s Estimated EITR for 2004 was 37% as of September 30, 2004. The decrease in the Estimated EITR was primarily due to: (i) the anticipated reversal, during 2005, of an $11,942,000 deferred tax asset valuation allowance associated with Southern Union's investment in CCE Holdings; (ii) the recognition of an 80% dividend received deduction on dividends expected to be received from Citrus during 2005; and (iii) the recognition of the Medicare Part D tax-free subsidy (see Note XI - Employee Benefits).

Southern Union is nearing completion of an income tax project assessing substantially all its temporary differences. The Company believes that this project will be completed by December 31, 2005. Upon the completion of this project, the Company may identify deferred income tax assets or liabilities that may be adjusted and could result in a decrease or increase in income tax expense. Management does not believe that the effect of such adjustments will have a material effect on the Company's consolidated financial statements.

Business Segment Results

Distribution Segment -The Distribution segment is primarily engaged in the local distribution of natural gas in Missouri, Pennsylvania, Massachusetts and Rhode Island. Its operations are conducted through the Company’s three regulated utility divisions: MGE, PG Energy and NEGC. Collectively, the utility divisions serve approximately 950,000 residential, commercial and industrial customers. The utility divisions’ operations are regulated as to rates and other matters by the regulatory commissions of the states in which each operates. The utility divisions’ operations are generally sensitive to weather and seasonal in nature, with a significant percentage of annual operating revenues and net earnings (losses) occurring in the traditional winter heating season in the first and fourth calendar quarters.

The following table provides summary data regarding the Distribution segment’s results of operations for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(thousands of dollars)						(thousands of dollars)
Financial Results
Operating revenues	$	137,000		$	124,021		$	960,953		$	936,575
Cost of gas and other energy		(73,772	)		(65,352	)		(633,091	)		(617,887	)
Revenue-related taxes		(4,647	)		(4,435	)		(33,604	)		(32,369	)
Net operating revenues, excluding depreciation and amortization amortization		58,581			54,234			294,258			286,319
Operating expenses:
Operating, maintenance, and general		45,536			50,971			154,391			155,876
Depreciation and amortization		15,671			15,071			47,433			43,409
Taxes other than on income and revenues		(835	)		6,288			10,583			19,152
Total operating expenses		60,372			72,330			212,407			218,437
Operating income (loss)		(1,791	)		(18,096	)		81,851			67,882
Other income (expense), net		(568	)		497			(491	)		1,367
EBIT	$	(2,359	)	$	(17,599	)	$	81,360		$	69,249
Operating Information
Gas sales volumes in millions of cubic feet (MMcf)		7,774			8,177			75,393			80,024
Gas transported volumes in MMcf		12,145			11,668			44,106			44,407

35

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Weather:
Degree days:
MGE service territories		25			15			2,794			2,958
PG Energy service territories		42			120			4,098			4,092
NEGC service territories		45			71			3,908			3,838
Percent of 30-year measure:
MGE service territories		38	%		23	%		86	%		91	%
PG Energy service territories		25	%		76	%		101	%		103	%
NEGC service territories		40	%		63	%		103	%		102	%

Operating Revenues.Operating revenues for the three months ended September 30, 2005 compared with the three months ended September 30, 2004 increased $12,979,000 to $137,000,000, while gas purchase and other energy costs increased $8,420,000 to $73,772,000. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 19% increase in the average cost of gas from $7.99 per thousand cubic feet (Mcf) in 2004 to $9.49 per Mcf in 2005, which was partially offset by a 5% decrease in gas sales volumes to 7,774 million cubic feet (MMcf) in 2005 from 8,177 MMcf in 2004. The increase in the average cost of gas is due to increases in market prices throughout the Company’s distribution system as a result of competitive pricing occurring within the entire energy industry. The decrease in gas sales volumes is primarily due to a slight decrease in the average number of gas sales customers served in the Company’s NEGC and MGE service territories. Operating revenues for the three months ended September 30, 2005 were also impacted by the $22,370,000 annual increase to base revenues granted to MGE effective October 2, 2004.

Gas purchase costs generally do not directly affect earnings since these costs are passed on to customers pursuant to purchase gas adjustment clauses. Accordingly, although changes in the cost of gas may cause the Company’s operating revenues to fluctuate, net operating revenues are generally not affected by increases or decreases in the cost of gas. Increases in gas purchase costs indirectly affect earnings as the customer’s bill increases, usually resulting in increased bad debt and collection costs being recorded by the Company.

Operating revenues for the nine months ended September 30, 2005 compared with the nine months ended September 30, 2004 increased $24,378,000 to $960,953,000 while gas purchase and other energy costs increased $15,204,000 to $633,091,000. The increase in both operating revenues and gas purchase costs between periods was primarily due to a 9% increase in the average cost of gas from $7.72 per Mcf in 2004 to $8.40 per Mcf in 2005, which was partially offset by a 6% decrease in gas sales volumes to 75,393 MMcf in 2005 from 80,024 MMcf in 2004. The increase in the average cost of gas is due to increases in market prices throughout the Company’s distribution system. The decrease in gas sales volumes is primarily due to the impact of warmer weather in 2005 as compared with 2004 in the Company’s MGE and PG Energy service territories and a slight decrease in the average number of gas sales customers served in the Company’s NEGC and PG Energy service territories. Operating revenues for the nine months ended September 30, 2005 were also impacted by the annual increase to base revenues granted to MGE, as previously noted, and a $3,000,000 increase in transportation revenues primarily due to higher average rates on new contracts and lower regulatory refunds to customers in 2005.

Net Operating Revenues. Net operating revenues for the three months ended September 30, 2005 increased by $4,347,000, to $58,581,000. Net operating revenues for the nine months ended September 30, 2005 increased by $7,939,000 to $294,258,000. Net operating revenues and earnings are primarily dependent upon gas service rates and gas sales volumes. The level of gas sales volumes is sensitive to the variability of the weather as well as the timing of acquisitions. Service rates in 2005 were positively impacted by the annual increase to base revenues granted to MGE, as previously noted. In addition, net operating revenues for the nine months ended September 30, 2005 were positively impacted by an increase in transportation revenues, as previously noted.

Operating Expenses. Operating, maintenance and general expenses for the three months ended September 30, 2005 decreased $5,435,000 to $45,536,000. Operating expenses were impacted by $5,241,000 of decreased pension costs primarily due to the deferral of MGE pension expense pursuant its October 2004 rate case and $3,051,000 of decreased bad debt expense primarily as a result of more aggressive collection efforts in 2005. These decreases were partially offset by increased other operating expenses, including payroll and benefit costs and outside service costs relating to subcontract labor and collection agency and call center fees.

36

Operating, maintenance and general expenses for the nine months ended September 30, 2005 decreased $1,485,000 to $154,391,000. Operating expenses were impacted by $3,699,000 of decreased pension costs as well as $3,587,000 of decreased bad debt expense, both previously discussed. These decreases were partially offset by $1,793,000 of increased outside service fees related to environmental matters as well as increased other operating expenses including benefit costs and outside professional fees related to health and safety matters.

As of September 30, 2005, the Company believes that its reserves for bad debts are adequate based on historical trends and collections. However, to the extent that the cost of gas remains above historical averages, the Company may experience increased pressure on collections and exposure to bad debts that could impact the operating results of this segment during the remainder of 2005.

Depreciation and amortization expense for the three months ended September 30, 2005 increased $600,000 to $15,671,000. Depreciation and amortization expense for the nine months ended September 30, 2005 increased $4,024,000 to $47,433,000. The increase in both periods was primarily due to normal growth in plant and financial information systems placed in service during 2005.

Taxes Other Than On Income and Revenues. Taxes other than on income and revenues for the three months ended September 30, 2005 decreased $7,123,000 to a credit of $835,000. Taxes other than on income and revenues for the nine months ended September 30, 2005 decreased $8,569,000 to $10,583,000. The decrease in both periods was primarily due to property tax refunds relating to the reassessment of property owned by MGE covering the tax years 2002 to 2004 as well as a favorable Accounting Authority Order granted by the MPSC that will allow MGE to defer all property tax expense related to Kansas storage gas (approximately $1,000,000 per year) for tax years 2004 to 2006, MGE will be required to amortize the deferred amounts at the beginning of the month following a final judicial determination of the legality of the Kansas property taxes and the amortization will occur over a five-year period.

Supplemental Operating Information. The following table sets forth additional gas throughput and related information for the Company’s Distribution segment for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Average number of customers:
Residential		832,298		836,649			844,810			845,710
Commercial		100,278		99,898			101,056			102,762
Industrial and irrigation		419		417			424			427
Public authorities and other		395		388			399			387
Total average customers served		933,390		937,352			946,689			949,286
Transportation customers		3,021		2,690			3,043			2,689
Total average gas sales and transportation customers		936,411		940,042			949,732			951,975
Gas sales in MMcf:
Residential		4,526		5,049			57,622			61,906
Commercial		2,342		2,581			23,872			25,601
Industrial and irrigation		676		699			2,256			2,158
Public authorities and other		21		15			233			219
Gas sales billed		7,565		8,344			83,983			89,884
Net change in unbilled gas sales		209		(167	)		(8,590	)		(9,860	)
Total gas sales		7,774		8,177			75,393			80,024
Gas transported		12,145		11,668			44,106			44,407
Total gas sales and gas transported		19,919		19,845			119,499			124,431

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	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Gas sales revenues (thousands of dollars):
Residential	$	81,123	$	78,418		$	717,263		$	703,784
Commercial		33,363		31,843			275,652			270,889
Industrial and irrigation		8,709		6,286			25,240			20,190
Public authorities and other		400		245			2,570			2,206
Gas revenues billed		123,595		116,792			1,020,725			997,069
Net change in unbilled gas sales revenues		4,646		(1,412	)		(90,143	)		(91,724	)
Total gas sales revenues		128,241		115,380			930,582			905,345
Gas transportation revenues		6,176		5,741			27,915			24,915
Other revenues		2,583		2,900			2,456			6,315
Total operating revenues	$	137,000	$	124,021		$	960,953		$	936,575
Gas sales revenue per thousand cubic feet billed:
Residential	$	17.92	$	15.53		$	12.45		$	11.37
Commercial		14.25		12.34			11.55			10.58
Industrial and irrigation		12.88		8.99			11.19			9.36
Public authorities and other		18.72		16.33			10.95			10.07

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 Southwest and from the Gulf Coast to Florida, and also provides LNG terminalling and regasification services. Its operations are conducted through Panhandle Energy and the Company’s 50% equity investment in CCE Holdings. Panhandle Energy provides approximately 500 customers in the Midwest and Southwest with a comprehensive array of transportation and storage services. Panhandle Energy also operates one of the largest LNG terminal facilities in North America. Through its investment in CCE Holdings, Southern Union has an interest in and operates the Transwestern and FGT interstate gas pipelines. Transwestern accesses natural gas supply from the San Juan Basin, western Texas and mid-continent producing areas, and transports these volumes to markets in California, the Southwest and the key trading hubs in western Texas. FGT is the principal transporter of natural gas to the Florida energy market through a pipeline system that connects the natural gas supply basins of the Texas and Louisiana Gulf Coasts and the Gulf of Mexico to Florida. Southern Union reports the Company’s share of CCE Holdings’ earnings as earnings from unconsolidated investments in the Consolidated Statement of Operations. The Transportation and Storage segment’s operations are regulated as to rates and other matters by the Federal Energy Regulatory Commission (FERC), and are somewhat sensitive to the weather and seasonal in nature with a significant percentage of annual operating revenues and net earnings occurring in the traditional winter heating season.

The following table provides summary data regarding the Transportation and Storage segment’s results of operations for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Financial Results
Reservation revenue	$	83,759	$	77,081	$	265,543	$	256,156
LNG terminalling revenue		15,046		15,004		41,815		42,847
Commodity revenue		15,040		14,719		48,018		49,408
Other revenue		2,100		2,460		6,390		7,273
Total operating revenues		115,945		109,264		361,766		355,684
Operating expenses:
Operating, maintenance, and general		47,378		49,125		145,693		151,434
Depreciation and amortization (1)		15,145		15,178		45,537		42,008
Taxes other than on income and revenues		7,313		7,044		21,518		21,244
Total operating expenses		69,836		71,347		212,748		214,686
Operating income		46,109		37,917		149,018		140,998
Earnings from unconsolidated investments		21,916		54		57,569		154
Other income, net		72		446		1,387		716
EBIT	$	68,097	$	38,417	$	207,974	$	141,868
Operating Information
Gas transported in trillions of British thermal units (Tbtu)		250		302		907		957

(1) Depreciation and amortization reflected herein for the nine months ended September 30, 2004 is $3,193,000 less than that reported by Panhandle Energy in its separate SEC filing for the same period. The outside appraisals for the Panhandle Energy assets acquired and liabilities assumed were finalized after Southern Union had filed its Form 10-Q for the quarter ended December 31, 2003, but prior to Panhandle Energy filing its Form 10-K for the year ended December 31, 2003. Panhandle Energy was able to reflect depreciation and amortization expense consistent with the final outside appraisals as of December 31, 2003, which Southern Union recognized during the quarter ended March 31, 2004.

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Operating Revenues.Operating revenues for the three months ended September 30, 2005 compared with the three months ended September 30, 2004 increased $6,681,000 to $115,945,000. This increase was primarily due to an increase in reservation revenue of $6,678,000 due to higher average rates on new contracts and an increase in capacity sold. Reservation average rates 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. LNG terminalling revenues increased slightly due to increased contract capacity with BG LNG including the addition of the expanded vaporization capacity, offset by lower LNG volumes received.

Operating revenues for the nine months ended September 30, 2005 compared with the nine months ended September 30, 2004 increased $6,082,000 to $361,766,000. Such increase was primarily due to an increase in reservation revenue of $9,387,000 due to higher average rates on new contracts and an increase in capacity sold. Reservation average rates 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. This increase was partially offset by a decrease in LNG terminalling revenue of $1,032,000 due to reduced LNG volumes received, a decrease in commodity revenue of $1,390,000 due to a reduction in commodity volumes of six percent, primarily on Trunkline Gas resulting from low market spreads and lower LNG volumes and a decrease in other revenue of $883,000 primarily due to lower liquid volumes. Commodity revenues are dependent upon a number of variable factors, including weather, storage levels, and customer demand for firm, interruptible and parking services.

Operating Expenses. Operating, maintenance and general expenses for the three months ended September 30, 2005 decreased $1,747,000 to $47,378,000. Such decrease was primarily due to a reduction of administrative and other costs of $1,606,000 primarily associated with the workforce reduction and other synergies associated with the integration of CrossCountry Energy, reduced power costs of $1,019,000 due to lower LNG volumes received, and decreased corporate charges of $596,000. Such decrease was partially offset by the net recovery of previously underrecovered fuel costs of $1,790,000 in 2004.

Operating, maintenance and general expenses for the nine months ended September 30, 2005 decreased $5,741,000 to $145,693,000. Such decrease included a reduction in certain operating and maintenance expenses of approximately $6,200,000 primarily due to the timing of maintenance activities generally performed during off-peak times, more of which was performed earlier in the summer months in 2004 and synergies associated with the workforce reduction undertaken in the fourth quarter of 2004 associated with the integration of CrossCountry Energy. Administrative costs were also reduced by $3,800,000 primarily due to the workforce reduction and other synergies associated with the integration of CrossCountry Energy. In addition, electric power costs decreased by $1,757,000 due to a reduction in LNG volumes received. These decreases were partially offset by the higher net recovery of previously underrecovered fuel volumes of $4,206,000 in 2004.

Depreciation and amortization expense for the nine months ended September 30, 2005 increased $3,529,000 to $45,537,000 primarily due to the $3,193,000 purchase accounting adjustments recorded during the first quarter of 2004, as previously noted.

Earnings from Unconsolidated Investments. Earnings from unconsolidated investments for the three months ended September 30, 2005 and 2004 were $21,916,000 and $54,000, respectively. The increase in earnings from unconsolidated investments in 2005 is primarily due to $21,855,000 of earnings from CCE Holdings, which the Company acquired on November 17, 2004.

Earnings from unconsolidated investments for the nine months ended September 30, 2005 and 2004 were $57,569,000 and $154,000, respectively. The increase in earnings from unconsolidated investments in 2005 is primarily due to $57,399,000 of earnings from CCE Holdings in 2005.

39

Liquidity and Capital Resources

Operating Activities. The seasonal nature of the Company’s business results in a high level of cash flow needs to finance gas purchases and other energy costs, outstanding customer accounts receivable and certain tax pay-ments. Additionally, significant cash flow needs may be required to finance current debt service obligations. To provide these funds, as well as funds for its continuing construction and maintenance programs, the Com-pany has historically used cash flows from operations and its credit facilities. Because of available credit and the ability to obtain various types of market financing, combined with anticipated cash flows from operations, management believes it has adequate financial flexibility and access to financial markets to meet its short-term cash needs.

The Company has increased the scale of its natural gas transportation, storage and distribution operations and the size of its customer base by pursuing and consum-mating business acquisitions. On November 17, 2004, the Company acquired a 50% equity interest in CCE Holdings (see Note II --Acquisitions and Sales). Acquisitions require a substantial increase in expenditures that may need to be financed through cash flow from operations or future debt and equity offerings. The availability and terms of any such financing sources will depend upon various factors and conditions such as the Company’s combined cash flow and earnings, the Company’s resulting capital structure, and conditions in the financial markets at the time of such offerings. Acquisitions and 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 acquisition financing or refinancing 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.

Cash flows provided by operating activities were $251,870,000 for the nine months ended September 30, 2005 compared with cash flows provided by operating activities of $275,512,000 for the same period in 2004. Cash flows provided by operating activities before changes in operating assets and liabilities for 2005 were $233,156,000 compared with $218,073,000 for 2004. Changes in operating assets and liabilities provided cash of $18,714,000 in 2005 and $57,439,000 in 2004. Working capital was positively impacted by changes in deferred purchased gas costs, increases in customer deposits, changes in prepaids and other assets and changes in deferred charges. Working capital was negatively impacted by changes in deferred credits, decreases in accounts payable, increases in inventories, changes in net gas imbalances and changes in accounts receivable.

At September 30, 2005 and December 31, 2004, the Company’s primary source of liquidity included borrowings available under the Company’s credit facilities. On September 29, 2005, the Company entered into a Fourth Amended and Restated Revolving Credit Facility in the amount of $400,000,000 (the Long-Term Facility). The Long-Term Facility has a five-year term and matures on May 28, 2010. The Long-Term Facility replaced the Company’s May 28, 2004 long-term credit facility in the same amount. Borrowings under the Long-Term Facility are available for Southern Union’s working capital, letter of credit requirements and other general corporate purposes. The Company has additional availability under uncommitted line of credit facilities (Uncommitted Facilities) with various banks. The Long-Term Facility is subject to a commitment fee based on the rating of the Company’s senior unsecured notes (the Senior Notes). As of September 30, 2005, the commitment fees were an annualized 0.11%.

On July 14, 2005, the Company amended an existing uncommitted short-term bank note to increase the principal amount from $15,000,000 to $65,000,000 in order to provide additional liquidity. The note is repayable upon demand and the Company borrowed $50,000,000 under the note on July 19, 2005 for an initial period of six months at a rate of 4.54%, which is based upon six-month LIBOR plus 70 basis points.

Balances of $273,000,000 and $292,000,000 were outstanding under the Company’s credit facilities at effective interest rates of 6.25% and 3.20% at September 30, 2005 and December 31, 2004, respectively. As of October 28, 2005, there was a balance of $305,000,000 outstanding under the Company’s credit facilities at an effective interest rate of 4.59%.

Investing Activities. Cash flows used in investing activities were $212,250,000 for the nine months ended September 30, 2005 compared with $193,785,000 for the same period in 2004.

40

During the nine months ended September 30, 2005 and 2004, the Company expended $211,925,000 and $192,303,000, respectively, for capital expenditures excluding acquisitions. The Transportation and Storage segment incurred $150,161,000 and $109,509,000 of capital expenditures during the nine months ended September 30, 2005 and 2004, respectively. Included in these capital expenditures were approximately $74,000,000 and $66,000,000 relating to the Phase I and Phase II expansions of the LNG facility of Trunkline LNG Company, LLC (Trunkline LNG), and the construction by Trunkline Gas Company (Trunkline) of a 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal in 2005 and 2004, respectively (see Note XIII -- Regulation and Rates -- Panhandle Energy). The remaining capital expenditures for the respective periods primarily related to Distribution segment system replacement and expansion. Included in these capital expenditures were $9,093,000 and $5,928,000 for the MGE safety program during the nine months ended September 30, 2005 and 2004, respectively. Cash flow provided by operations has historically been utilized to finance capital expenditures and is expected to be the primary source for future capital expenditures.

The Company estimates expenditures associated with the Phase I and Phase II LNG terminal expansions to be approximately $20,000,000 for the remainder of 2005 and approximately $28,000,000 in 2006. These estimates were developed for budget planning purposes and are subject to revision.

In August 2005, Trunkline announced preliminary plans to expand its natural gas pipeline in East Texas through construction of an approximately 45-mile, 30-inch pipeline loop into Louisiana. The expansion project, which is subject to regulatory approval, will give customers increased access to additional Texas supply and provide an additional capacity of approximately .4 bcf/day. The expansion is estimated to be in service in 2007 at an estimated cost of $80,000,000.

Late in the third quarter of 2005, Hurricanes Katrina and Rita came ashore along the Upper Gulf Coast after coming through the Gulf of Mexico. These hurricanes caused modest damage to property and equipment owned by Sea Robin, Trunkline, and Trunkline LNG, the ultimate cost of which cannot yet be accurately predicted. However, based on the preliminary damage assessments which are underway, management believes that there will be future revenue, expense, and capital impacts of Hurricanes Rita and Katrina in 2005 and 2006, primarily on Sea Robin and Trunkline LNG. For 2005 and 2006, the Company estimates revenue losses of approximately $11,000,000 to $13,000,000, expense increases of up to $5,000,000, and additional capital outlays of approximately $14,000,000 to $18,000,000. Estimated expenses and capital outlays primarily include repair and replacement of equipment lost or damaged in the hurricanes, potential abandonment costs for certain facilities, which will be impacted by producer decisions regarding rebuilding their damaged platforms and reconnecting their gas reserves to Panhandle Energy’s pipelines, higher insurance premiums, higher LNG construction costs, as well as employee assistance related expenses. The revenue losses expected relate primarily to reduced volumes on Sea Robin into 2006 and some delays in the completion of Trunkline LNG’s Phase I and Phase II expansions which are currently anticipated.  Trunkline LNG and the contractor on the LNG project are currently engaged in active discussions to reach resolution on revised project timing and additional costs to the respective parties associated with the hurricane impacts.  The Company currently expects the delays to be eight weeks and five weeks for Phase I and Phase II, respectively. No significant expenditures had occurred nor accruals been made with respect to either hurricane as of September 30, 2005. Additionally, the Company anticipates reimbursement from its property insurance carrier for damages from Hurricane Rita in excess of its $5,000,000 deductible. However, such reimbursement could be further limited depending on the magnitude of the claims made to the carrier by all of its covered parties for Hurricane Rita, due to its $1 billion cap on total payout per incident. Based on the information available at this time, management does not expect the ultimate impact of the damages caused by these two hurricanes to have a material adverse impact on the Company.

In October 2005, Panhandle Eastern Pipe Line began an enhancement of its east end in order to increase capacity and improve system integrity and efficiency. This enhancement is estimated to be completed in 2007 at an estimated cost of $86,000,000.

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Financing Activities. Cash flows used in financing activities were $69,037,000 for the nine months ended September 30, 2005 compared with $75,165,000 for the same period in 2004. Financing activity cash flow changes were primarily due to the net impact of acquisition financing, repayment and issuance of debt, net borrowings under the revolving credit facilities and the issuance of common stock. As a result of these financing transactions, the Company’s total debt to total capital ratio at September 30, 2005 was 55.5%, compared with 63.8% at September 30, 2004. The Company’s effective debt cost rate under the current debt structure was 6.02% (which includes interest and the amortization of debt issuance costs and redemption premiums on refinanced debt) as of September 30, 2005.

On April 29, 2005, Panhandle Energy refinanced LNG Holdings’ outstanding bank loans of $255,626,000, due 2007, for the same principal amount and extended the maturity date from January 31, 2007 to March 15, 2007. The new notes have substantially the same terms as the old notes with the exception of the following primary differences: (i) the assets of Trunkline LNG are not pledged as collateral; (ii) Panhandle Eastern Pipe Line and Trunkline LNG each severally provided a guarantee for the notes; and (iii) the interest rate is tied to the rating of Panhandle Eastern Pipe Line’s unsecured funded debt.

On February 11, 2005, Southern Union issued 2,000,000 of its 5% Equity Units at a public offering price of $50 per unit, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $97,378,000. Southern Union used the proceeds to repay the balance of the bridge loan used to finance a portion of its investment in CCE Holdings and to repay borrowings under its credit facilities. Each equity unit consists of a 1/20^th interest in a $1,000.00 principal amount of Southern Union’s 4.375% Senior Notes due 2008 (see Note IX - Long-Term Debt and Capital Lease Obligations) and a forward stock purchase contract that obligates the holder to purchase Southern Union common stock on February 16, 2008, at a price based on the preceding 20-day average closing price (subject to a minimum and maximum conversion price per share of $23.44 and $29.30, respectively, which are subject to adjustments for future stock splits or stock dividends). The equity units carry a total annual coupon of 5.00% (4.375% annual face amount of the senior notes plus 0.625% annual contract adjustment payments).

On February 9, 2005, Southern Union issued 14,913,042 shares of its common stock at $23.00 per share, resulting in net proceeds, after underwriting discounts and commissions and other transaction related costs, of $331,772,000. Southern Union used the net proceeds to repay a portion of the bridge loan used to finance a portion of its investment in CCE Holdings.

On March 12, 2004, Panhandle Energy issued $200,000,000 of its 2.75% Senior Notes due 2007. Panhandle Energy used a portion of the net proceeds of that offering to fund the redemption of the remaining $146,080,000 principal amount of its 6.125% Senior Notes due 2004 that matured on March 15, 2004, and to provide working capital to the Company. Panhandle Energy used a portion of the remaining net proceeds to repay the remaining $52,455,000 principal amount of its 7.875% Senior Notes due 2004 that matured on August 15, 2004.

The Company has a scheduled debt maturity of $125,000,000 on August 16, 2006, due to the initial maturity of the 2.75% Senior Notes that were issued in connection with the sale of $125,000,000 of its 5.75% Equity Units by the Company on June 12, 2003 (see Note VII - Stockholders’ Equity). The Company is currently evaluating various options it has with respect to this obligation, and it does not anticipate any material impact on its liquidity or financial condition from this upcoming event.

The Company has a currently effective shelf registration statement on file with the SEC for a total principal amount of $1,000,000,000 in securities of which $219,813,000 in securities is available for issuance as of October 28, 2005.

The Company’s ability to arrange financing, including refinancing, and its cost of capital are dependent on various factors and conditions, including: general economic and capital market conditions; maintenance of acceptable credit ratings; credit availability from banks and other financial institutions; investor confidence in the Company, its competitors and peer companies in the energy industry; market expectations regarding the Company’s future earnings and probable cash flows; market perceptions of the Company’s ability to access capital markets on reasonable terms; and provisions of relevant tax and securities laws.

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Other Matters

Customer Concentrations. In the Transportation and Storage segment, aggregate sales to Panhandle Energy’s top 10 customers accounted for 66% of segment operating revenues and 18% of the Company’s total operating revenues for the nine months ended September 30, 2005. This included sales to ProLiance Energy, LLC, a nonaffiliated local distribution company and gas marketer, which accounted for 16% of segment operating revenues, sales to BG Energy Holdings Limited, a nonaffiliated gas marketer, which accounted for 15% of segment operating revenues and sales to Ameren Corporation, which accounted for 11% of segment operating revenues. No other customer accounted for 10% or more of the Transportation and Storage segment operating revenues, and no single customer or group of customers under common control accounted for 10% or more of the Company’s total operating revenues for the nine months ended September 30, 2005.

Off-Balance Sheet Arrangements. As of September 30, 2005, the Company had guarantees related to PEI Power of $7,710,000, letters of credit related to insurance claims and other commitments of $7,969,000 and surety bonds related to construction or repair projects of approximately $3,643,000. The Company believes that the likelihood of having to make payments under the letters of credit or the surety bonds is remote and therefore has made no provisions for making payments under such instruments.

On April 19, 2005, a subsidiary of the Company, in accordance with the terms of a previously executed guarantee, was required to pay a bank $4,000,000 (see Note VI - Unconsolidated Investments).

Regulatory. The majority of the Company's business activities is subject to various regulatory authorities. The Com-pany's financial condition and results of operations have been and will continue to be dependent upon the receipt of adequate and timely ad-justments in rates. For additional information on regulatory matters concerning the Company, see Note XIII - Regulation and Rates.

Subsequent Events. On November 8, 2005, the Company announced that Thomas F. Karam, a Director and President and Chief Operating Officer of the Company, resigned from his positions with the Company and its subsidiaries, divisions, joint ventures and other affiliates, effective immediately. In connection with Mr. Karam's departure, on November 7, 2005, the Company and Mr. Karam entered into a Separation Agreement and General Release (the Agreement). Pursuant to the Agreement, which supersedes the terms and conditions of Mr. Karam's employment agreement, Mr. Karam will receive certain severance, bonus and non-competition payments as well as certain other distributions and reimbursements. The Company expects to record a $3,712,000 fourth quarter charge related to the severance and bonus payments under the Agreement and to amortize the $540,000 payment for the non-competition arrangements over its two-year term. Mr. Karam will also repay a promissory note in favor of Southern Union, which has an outstanding principal balance of $2,383,000. In addition, Mr. Karam will provide consulting services to the Company for a period of two years commencing January 2006.

Effective upon Mr. Karam's resignation, the Board of Directors of the Company appointed George L. Lindemann, Chairman and Chief Executive Officer of the Company, to the office of President. In recognition of the additional responsibilities to be assumed by Mr. Lindemann, the Compensation Committee of the Board of Directors also authorized an increase in Mr. Lindemann's annual base salary from $925,000 to $1,500,000.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There are no material changes in market risks faced by the Company from those reported in the Company's Transition Report on Form 10-K, as amended, for the six months ended December 31, 2004.

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7 and 7A in the Company's Transition Report on Form 10-K, as amended, for the six months ended December 31, 2004, in addition to the interim consolidated financial statements, accompanying notes, and Management's Discussion and Analysis of Results of Operations and Financial Condition presented in Items 1 and 2 of Part I of this Quarterly Report on Form 10-Q.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

Southern Union has established disclosure controls and procedures to ensure that information required to be disclosed by the Company, including consolidated entities, in reports filed or submitted under the Securities Exchange Act of 1934, as amended (Exchange Act) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company performed an evaluation under the supervision and with the participation of management, including its Chief Executive Officer (CEO) and Chief Financial Officer (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, 2005.

Changes in Internal Controls.

Management’s assessment of internal control over financial reporting as of December 31, 2004, was included in Southern Union’s amended Transition Report on Form 10-K filed on June 27, 2005. As of January 1, 2005, the Company began migrating to a new enterprise-wide general ledger and financial reporting system, including certain subsystems, which were implemented across all business units throughout 2005. As of October 28, 2005 this system migration has been substantially completed.

There have been no other changes in internal control over financial reporting that occurred during the first three quarters of 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Cautionary Statement Regarding Forward-Looking Information

This Management’s Discussion and Analysis of Results of Operations and Financial Condition and other sections of this Quarterly Report on Form 10-Q contain forward-looking statements that are based on current expectations, estimates and projections about the industry in which the Company operates, management’s beliefs and assumptions made by management. Words such as “expects,”“anticipates,”“intends,”“plans,”“believes,”“seeks,”“estimates,” variations of such words and similar expressions are intended to identify such forward-looking statements. Similarly, statements that describe the Company’s objectives, plans or goals are or may be forward-looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions, which are difficult to predict and many of which are outside the Company’s control. Therefore, actual results, performance and achievements may differ materially from what is expressed or forecasted in such forward-looking statements. The Company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned not to put undue reliance on such forward-looking statements. Stockholders may review the Company’s reports filed in the future with the SEC for more current descriptions of developments that could cause actual results to differ materially from such forward-looking statements.

Factors that could cause actual results to differ materially from those expressed in our forward-looking statements include, but are not limited to, the following: cost of gas; gas sales volumes; gas throughput volumes and available sources of natural gas; discounting of transportation rates due to competition; customer growth; abnormal weather conditions in the Company’s service territories; the Company’s ability to control costs successfully and achieve operating efficiencies, including the purchase and implementation of new technologies for achieving such efficiencies; impact of relations with labor unions of bargaining-unit employees; the receipt of timely and adequate rate relief and the impact of future rate cases or regulatory rulings; the outcome of pending and future litigation; the speed and degree to which competition is introduced to our gas distribution business; new legislation and government regulations and proceedings affecting or involving the Company; unanticipated environmental liabilities; the Company’s ability to comply with or to challenge successfully existing or new environmental regulations; changes in business strategy and the success of new business ventures; the risk that the businesses acquired and any other businesses or investments that Southern Union has acquired or may acquire may not be successfully integrated with

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the businesses of Southern Union; 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; factors affecting operations such as maintenance or repairs, environmental incidents or gas pipeline system constraints; the Company’s or any of its subsidiaries’ debt securities ratings; the economic climate and growth in the Company’s industry and service territories and competitive conditions of energy markets in general; inflationary trends; changes in gas or other energy market commodity prices and interest rates; the current market conditions causing more customer contracts to be of shorter duration, which may increase revenue volatility; the possibility of war or terrorist attacks; the nature and impact of any extraordinary transactions such as any acquisition or divestiture of a business unit or any assets. These are representative of the factors that could affect the outcome of the forward-looking statements. In addition, such statements could be affected by general industry and market conditions, and general economic conditions, including interest rate fluctuations, federal, state and local laws and regulations affecting the retail gas industry or the energy industry generally, and other factors.

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 Note XIV - Commitments and Contingencies in this Quarterly Report on Form 10-Q and in Note XVIII - Commitments and Contingencies in Southern Union’s Transition Report on Form 10-K, as amended, for the six months ended December 31, 2004.

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 Note XIV - Commitments and Contingencies in this Quarterly Report on Form 10-Q and in Note XVIII - Commitments and Contingencies in Southern Union’s Transition Report on Form 10-K, as amended, for the six months ended December 31, 2004.

ITEM 6. EXHIBITS

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

10.1	Fourth Amended and Restated Revolving Credit Agreement between Southern Union 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.)
10.2	Separation Agreement and General Release between the Company and Mr. Brennan. (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.)
10.3	Change of Control Agreement between the Company and Ms. Edwards. (Filed as Exhibit 10.2 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)
10.4	Stock Option Agreement between the Company and Ms. Edwards. (Filed as Exhibit 10.3 to Southern Union’s Current Report on Form 8-K filed on July 5, 2005 and incorporated herein by reference.)
10.5	Separation Agreement and General Release between the Company and Mr. Kvapil. (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.)
10.6	Separation Agreement and General Release between the Company and Mr. Karam. (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.)
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, 2005	By   /S/ JULIE H. EDWARDS
	Senior Vice President and
	Chief Financial 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, 2005

/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, Julie H. Edwards, 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, 2005

/s/ JULIE H. EDWARDS

Julie H. Edwards

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, 2005, 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, 2005

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, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Julie H. Edwards, 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/ JULIE H. EDWARDS

Julie H. Edwards

Senior Vice President and

Chief Financial Officer

November 9, 2005

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.