SOUTHERN UNION CO - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

____________________________

FORM 10-Q

For the quarterly period ended

March 31, 2005

Commission File No. 1-6407

____________________________

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-0571592
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)


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

Registrant's telephone number, including area code: (570) 820-2400

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___

The number of shares of the registrant's Common Stock outstanding on April 29, 2005 was 105,592,087.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

FORM 10-Q

March 31, 2005

Table of Contents

PART I. FINANCIAL INFORMATION:	Page(s)

ITEM 1. Financial Statements (Unaudited):

Consolidated statement of operations - three months ended March 31, 2005 and 2004.	2

Consolidated balance sheet - March 31, 2005 and December 31, 2004.	3-4

Consolidated statement of stockholders’ equity and comprehensive income -- three months ended March 31, 2005.	5

Consolidated statement of cash flows - three months ended March 31, 2005 and 2004.	6

Notes to consolidated financial statements.	7-26

ITEM 2. Management's Discussion and Analysis of Results of Operation and Financial Condition.	27-38

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.	37

ITEM 4. Controls and Procedures.	37-38

PART II. OTHER INFORMATION:

ITEM 1. Legal Proceedings.

(See "COMMITMENTS AND CONTINGENCIES" in Notes to Consolidated Financial Statements)	17-24

ITEM 6. Exhibits.	38

SIGNATURES	39

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2005			2004
	*(thousands of dollars, except shares and per share amounts)*
Operating revenues:
Gas distribution	$	631,056		$	635,384
Gas transportation and storage		135,400			138,169
Other		1,100			1,016
Total operating revenues		767,556			774,569

Cost of gas and other energy		(448,472	)		(454,736	)
Revenue-related taxes		(22,239	)		(21,951	)
Net operating revenues, excluding depreciation and amortization		296,845			297,882

Operating expenses:
Operating, maintenance and general		95,822			106,809
Depreciation and amortization		31,311			26,419
Taxes, other than on income and revenues		14,130			14,299
Total operating expenses		141,263			147,527
Operating income		155,582			150,355

Other income (expenses):
Interest		(35,205	)		(31,055	)
Earnings (losses) from unconsolidated investments		15,341			(2	)
Other, net		(3,670	)		1,463
Total other expenses, net		(23,534	)		(29,594	)

Earnings before income taxes		132,048			120,761

Federal and state income taxes		39,852			45,394

Net earnings		92,196			75,367

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

Net earnings available for common shareholders	$	87,855		$	71,026


Net earnings available for common shareholders per share:
Basic	$	.89		$	.94
Diluted	$	.86		$	.92

Weighted average shares outstanding:
Basic		98,169,411			75,497,527
Diluted		102,575,756			77,566,078

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)

	March 31,			December 31,
	2005			2004
ASSETS	*(thousands of dollars)*

Property, plant and equipment:
Plant in service	$	3,887,630		$	3,869,221
Construction work in progress		275,837			237,283
		4,163,467			4,106,504
Less accumulated depreciation and amortization		(808,356	)		(778,876	)
Net property, plant and equipment		3,355,111			3,327,628

Current assets:
Cash and cash equivalents		47,493			30,053
Accounts receivable, billed and unbilled, net		365,515			333,492
Federal and state taxes receivable		3,285			--
Inventories		179,572			267,136
Gas imbalances - receivable		36,992			36,122
Prepayments and other		43,004			45,705
Total current assets		675,861			712,508

Goodwill		640,547			640,547

Deferred charges		196,684			199,064

Unconsolidated investments		646,451			631,893

Other		55,989			56,649















Total assets	$	5,570,643		$	5,568,289

See accompanying notes.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (Continued)

(Unaudited)

	March 31,			December 31,
	2005			2004
STOCKHOLDERS’ EQUITY AND LIABILITIES	*(thousands of dollars)*

Stockholders’ equity:
Common stock, $1 par value; authorized 200,000,000 shares; issued 105,912,589 and 90,762,650 shares, respectively	$	105,913		$	90,763
Preferred stock, no par value; authorized 6,000,000 shares; issued 920,000 shares		230,000			230,000
Premium on capital stock		1,520,615			1,204,590
Less treasury stock, 404,536 shares at cost		(12,870	)		(12,870	)
Less common stock held in trust: 1,099,337 and 1,198,034 shares, respectively		(16,637	)		(17,980	)
Deferred compensation plans		13,803			14,128
Accumulated other comprehensive loss		(57,946	)		(59,118	)
Retained earnings		135,899			48,044

Total stockholders’ equity		1,918,372			1,497,557

Long-term debt and capital lease obligation		2,177,419			2,070,353

Total capitalization		4,095,791			3,567,910

Current liabilities:
Long-term debt and capital lease obligation due within one year		76,985			89,650
Notes payable		120,000			699,000
Accounts payable		140,050			183,018
Federal, state and local taxes		39,801			33,946
Accrued interest		26,374			36,934
Customer deposits		13,340			13,156
Deferred gas purchases		79,852			3,709
Gas imbalances - payable		117,928			102,567
Other		139,003			151,856

Total current liabilities		753,333			1,313,836

Deferred credits		310,741			321,049

Accumulated deferred income taxes		410,778			365,494

Commitments and contingencies

Total stockholders’ equity and liabilities	$	5,570,643		$	5,568,289

See accompanying notes.

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		--		--		--			--			--			--			92,196			92,196
Net unrealized gain on hedging activities, net of tax		--		--		--			--			--			1,172			--			1,172
Comprehensive income		--		--		--			--			--			--			--			93,368
Preferred stock dividends		--		--		--			--			--			--			(4,341	)		(4,341	)
Distribution of common stock held in trust		--		--		391			--			613			--			--			1,004
Issuance of common stock		14,913		--		316,859			--			--			--			--			331,772
Issuance costs of equity units		--		--		(2,622	)		--			--			--			--			(2,622	)
Contract adjustment payment		--		--		(1,759	)		--			--			--			--			(1,759	)
Exercise of stock options		237		--		3,156			--			--			--			--			3,393
Balance March 31, 2005	$	105,913	$	230,000	$	1,520,615		$	(12,870	)	$	(3,239	)	$	(57,946	)	$	135,899		$	1,918,372

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.

SOUTHERN UNION COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2005			2004
	*(thousands of dollars)*

Cash flows provided by (used in) operating activities:
Net earnings	$	92,196		$	75,367
Adjustments to reconcile net earnings to net cash flows provided by operating activities:
Depreciation and amortization		31,311			26,419
Amortization of debt expense		2,370			490
Amortization of debt premium		(611	)		(2,693	)
Deferred income taxes		44,506			54,309
Provision for bad debts		3,049			5,844
Provision for impairment of other assets		4,508			--
(Earnings) losses from unconsolidated investments		(15,341	)		2
Other		(333	)		(463	)
Changes in operating assets and liabilities:
Accounts receivable, billed and unbilled		(35,073	)		(31,185	)
Gas imbalance receivable		(870	)		17,274
Accounts payable		(33,743	)		(1,361	)
Gas imbalance payable		15,361			(34,015	)
Accrued interest		(10,560	)		(13,036	)
Customer deposits		184			(245	)
Deferred gas purchase costs		77,569			17,236
Inventories		87,564			134,895
Deferred charges		1,586			1,522
Deferred credits		(10,308	)		10,977
Prepaids and other assets		1,935			4,446
Taxes and other liabilities		(23,412	)		(18,981	)
Net cash flows provided by operating activities		231,888			246,802
Cash flows used in investing activities:
Additions to property, plant and equipment		(51,060	)		(43,331	)
Notes receivable		--			(1,000	)
Other		(1,035	)		(4,532	)
Net cash flows used in investing activities		(52,095	)		(48,863	)
Cash flows used in financing activities:
Decrease in bank overdraft		(9,225	)		(3,480	)
Issuance of common stock		331,772			--
Issuance of equity units		100,000			--
Issuance cost of equity units		(2,622	)		--
Issuance of long-term debt		--			200,000
Issuance cost of debt		(479	)		(862	)
Issuance costs of preferred stock		--			(377	)
Dividends paid on preferred stock		(4,341	)		(4,052	)
Repayment of debt and capital lease obligation		(2,856	)		(162,691	)
Net payments under revolving credit facilities		(579,000	)		(176,500	)
Proceeds from exercise of stock options		3,393			797
Other		1,004			--
Net cash flows used in financing activities		(162,354	)		(147,165	)
Change in cash and cash equivalents		17,439			50,774
Cash and cash equivalents at beginning of period		30,054			20,810
Cash and cash equivalents at end of period	$	47,493		$	71,584

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	45,879		$	47,936
Income taxes	$	101		$	52

See accompanying notes.

I. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying unaudited interim consolidated financial statements of Southern Union Company (Southern Union and together with its subsidiaries, the Company) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for quarterly reports on Form 10-Q. These statements do not include all of the information and note disclosures required by 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 the Company’s Transition Report on Form 10-K 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) which are, in the opinion of management, necessary for a fair presentation 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 unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current period presentation.

Stock Based Compensation. The Company 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 the Company’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 and net earnings available for 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
	March 31,
	2005		2004

Net earnings, as reported	$	92,196	$	75,367
Deduct total stock-based employee compensation expense determined under fair value based method for all awards, net of related taxes		339		291
Pro forma net earnings	$	91,857	$	75,076

Net earnings available for common shareholders per share:
Basic -- as reported	$	.89	$	.94
Basic -- pro forma	$	.89	$	.94

Diluted -- as reported	$	.86	$	.92
Diluted -- pro forma	$	.84	$	.90

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, 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.

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

	Three Months Ended
	March 31,
	2005			2004

Net earnings	$	92,196		$	75,367
Other comprehensive income (loss):
Unrealized gain (loss) on hedging activities, net of tax (benefit)		2,134			(847	)
Realized gain on hedging activities in net earnings, net of tax		(962	)		(1,164	)
Other comprehensive income (loss)		1,172			(2,011	)
Comprehensive income	$	93,368		$	73,356

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

New Pronouncements.

Southern Union’s significant accounting policies are discussed in the Company’s 2004 Transition Report on Form 10-K. 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 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 FASB in 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 in the first annual reporting period beginning after June 15, 2005, 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. 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes’, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004.” On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed. The Act raises a number of issues with respect to accounting for income taxes. On December 21, 2004, the FASB issued a Staff Position regarding the accounting implications of the Act related to the deduction for qualified domestic production activities (FSP FAS 109-1), which is effective for periods subsequent to December 31, 2004. The guidance in the FSP applies to financial statements for periods ending after the date the Act was enacted. In FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the FASB decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. In most cases, a company’s existing deferred tax balances will not be impacted at the date of enactment. For some companies, the deduction could have an impact on their effective tax rate and, therefore, should be considered when determining the estimated annual rate used for interim financial reporting. The Company is currently evaluating the impact, if any, of this FSP 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 is effective, for entities to which the interpretations of FIN 46(R) have been applied, in the first reporting period beginning after March 31, 2005. Southern Union adopted this FSP as of March 31, 2005, the effect of which had no impact on the Company’s 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 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. This Interpretation is effective for the Company no later than the end of the fiscal year ending on December 31, 2005. The Company is currently evaluating the impact of this Interpretation on its consolidated financial statements.

FERC Proposed Accounting Release. In November 2004, the Federal Energy Regulatory Commission (FERC) issued an industry-wide Proposed Accounting Release that, if enacted as written, would require 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 was proposed to be effective January 1, 2005, following a period of public comment on the release. Comments were filed on January 19, 2005, including pipeline association comments suggesting that such costs be capitalized. The Company is awaiting a final release and cannot, at this time, predict the impact on its consolidated financial statements. Panhandle Energy has currently budgeted in 2005 approximately $22,000,000 for its pipeline integrity program, of which approximately $3,000,000 of currently capitalized costs would be required to be expensed pursuant to the release.

II. Acquisitions and Sales

On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy from Enron 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 (TWP) and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of Florida Gas Transmission Company (FGT). 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, reduced by total shares held in various rabbi trusts. 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, and convertible equity units. Shares held by rabbi trusts were included in diluted earnings per share because the Company’s obligation related to such shares may be settled by either the delivery of cash or shares of Company stock. A reconciliation of the shares used in the Basic and Diluted earnings per share calculations is shown in the following table.

	Three Months Ended
	March 31,
	2005		2004

Weighted average shares outstanding		99,302,702		76,685,377
Less weighted average rabbi trust shares outstanding		1,133,291		1,187,850
Weighted average shares outstanding - Basic		98,169,411		75,497,527

Weighted average shares outstanding		99,302,702		76,685,377
Add assumed conversion of equity units		1,937,934		30,674
Add assumed exercise of stock options		1,335,120		850,027
Weighted average shares outstanding - Diluted		102,575,756		77,566,078

There were no “anti-dilutive” options outstanding for the three months ended March 31, 2005 and 2004, respectively. At March 31, 2005, 1,099,337 shares of common stock were held by various rabbi trusts for certain of the Company’s benefit plans and 110,996 shares were held in a rabbi trust for certain employees who deferred receipt of Company shares 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 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 the Company’s 4.375% Senior Notes due 2008 (see Note IX - Debt and Capital Lease) and a forward stock purchase contract that obligates the holder to purchase Company 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 $24.61 and $30.76, respectively, which are subject to adjustments for future stock splits or stock dividends). The Company will issue between 3,250,711 shares and 4,063,389 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contract. Until the conversion date, the equity units will have a dilutive effect on earnings per share if the Company’s average common stock price for the period exceeds the settlement conversion price (see Note VII - Stockholders’ Equity).

On June 11, 2003, the Company issued 2,500,000 equity units at a public offering price of $50 per unit. Each equity unit consists of a $50.00 principal amount of the Company’s 2.75% Senior Notes due 2006 (see Note IX - Debt and Capital Lease) and a forward stock purchase contract that obligates the holder to purchase Company 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 $14.51 and $17.71, respectively, which are subject to adjustments for future stock splits or stock dividends). The Company will issue between 7,060,067 shares and 8,613,281 shares of its common stock (also subject to adjustments for future stock splits or stock dividends) upon the consummation of the forward purchase contract. Until the conversion date, the equity units will have a dilutive effect on earnings per share if the Company’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 three-month period ended March 31, 2005. As of March 31, 2005, the Company has goodwill of $640,547,000 from its Distribution segment. The Distribution segment is tested annually for impairment.

V. Deferred Charges and Credits

	March 31,		December 31,
	2005		2004
Deferred Charges
Pensions	$	55,931	$	55,848
Unamortized debt expense		35,978		37,869
Income taxes		32,661		32,661
Retirement costs other than pensions		23,739		24,459
Environmental		16,398		16,332
Service Line Replacement program		14,359		15,161
Other		17,618		16,734
Total Deferred Charges	$	196,684	$	199,064

As of March 31, 2005 and December 31, 2004, the Company’s deferred charges include regulatory assets relating to Distribution segment operations in the aggregate amount of $94,502,000 and $100,653,000, respectively, of which $58,624,000 and $60,611,000, respectively, is being recovered through current rates. As of March 31, 2005 and December 31, 2004, the remaining recovery period associated with these assets ranged from 1 month to 196 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.

	March 31,		December 31,
	2005		2004
Deferred Credits
Pensions	$	112,377	$	109,908
Retirement costs other than pensions		58,311		58,507
Cost of removal		29,744		29,337
Environmental		25,932		25,919
Derivative instrument liability		9,774		16,232
Customer advances for construction		14,665		14,740
Provision for self-insured claims		12,707		12,296
Investment tax credit		4,922		5,027
Other		42,309		49,083
Total Deferred Credits	$	310,741	$	321,049

As of March 31, 2005, and December 31, 2004, the Company’s deferred credits include regulatory liabilities relating to Distribution segment operations in the aggregate amount of $10,625,000 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

	March 31, 2005		December 31, 2004
Unconsolidated Investments
Equity investments:
CCE Holdings	$	631,117	$	615,861
Other		12,729		12,919
Investments at cost		2,605		3,113
Total unconsolidated investments	$	646,451	$	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 are recorded in earnings from unconsolidated investments in the Consolidated Statement of Operations. The Company’s equity investment balances include purchase price differences of $20,640,000 and $20,716,000 as of March 31, 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.

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

	Three Months Ended March 31, 2005
	CCE Holdings		Other

Income Statement Data:
Revenues	$	52,748	$	1,179
Operating income		25,107		198
Net income		30,664		151

Other Investments, at Cost. As of March 31, 2005, the Company, either directly or through a subsidiary owned common and preferred stock in 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, 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). Although Advent did not file for bankruptcy until April 8, 2005, Southern Union became aware of Advent’s bankruptcy prior to March 31, 2005 and consequently recorded a $4,000,000 liability associated with the guarantee by a subsidiary of the Company of a line of credit between Advent and JPMorgan Chase in the first quarter 2005. Subsequent to the bankruptcy filing, Advent defaulted on its $4,000,000 line of credit with JPMorgan Chase, 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 is reflected in other, net in the Consolidated Statement of Operations for the quarter ended March 31, 2005.

The Company plans to make timely and appropriate filings with the Bankruptcy Court, in order to preserve its rights and claims against Advent.

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: 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 other income (expense), net in its Consolidated Statement of Operations to reduce the carrying value of the security to its estimated fair value.

VII. Stockholders’ Equity

On February 11, 2005, the Company issued 2,000,000 equity units at a public offering price of $50 per unit, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $97,378,000. The proceeds were used to repay the balance of the bridge loan used to finance a portion of Southern Union’s investment in CCE Holdings and to repay borrowings under the Company’s credit facilities. Each equity unit consists of a stock purchase contract for the purchase of shares of the Company’s common stock and, initially, a senior note due February 16, 2008, issued pursuant to the Company’s existing indenture. 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). Each stock purchase contract issued as a part of the equity units carries a maximum conversion premium of up to 25% over the $24.61 issuance price of the underlying shares of the Company’s common stock. 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 the Company’s common 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, the Company issued 14,913,042 shares of common stock at $23.00 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $331,772,000. The net proceeds were used to repay a portion of the bridge loan used to finance a portion of Southern Union’s investment in CCE Holdings.

On July 30, 2004, the Company issued 4,800,000 shares of common stock at the public offering price of $18.75 per share, resulting in net proceeds to the Company, after underwriting discounts and commissions and other transaction related costs, of $86,563,000. The Company also sold 6,200,000 shares of the Company’s 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 the Company’s common stock at the same price, which was exercised by the underwriters. Under the terms of the forward sale agreements, the Company 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) through 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. The total net proceeds from the settlement of the forward sale agreements were used to fund a portion of the Company’s equity 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. The Company is party to interest rate swap agreements with an aggregate notional amount of $191,722,000 as of March 31, 2005 that fix the interest rate applicable to floating rate long-term debt and which qualify for hedge accounting. For the three months ended March 31, 2005, there was no swap ineffectiveness. For the three months ended March 31, 2004, the amount of swap ineffectiveness was not significant. As of March 31, 2005, floating rate LIBOR-based interest payments are exchanged for weighted average fixed rate interest payments of 6.09%. As such, payments, in excess of the liability recorded, or receipts on interest rate swap agreements are recognized as adjustments to interest expense. As of March 31, 2005 and December 31, 2004, the fair value liability position of the swaps was $7,486,000 and $11,053,000, respectively.

On April 29, 2005, the Company refinanced the LNG bank loans of $255,626,000 for the same amount and terminated the related interest rate swaps (see Note IX - Debt and Capital Lease). As a result, a gain of $3,465,000 ($2,072,000 net of tax) will be reflected in accumulated other comprehensive income in the Consolidated Balance Sheet and will be amortized to interest expense through the maturity date of the original bank loans in 2007.

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 March 31, 2005, approximately $981,000 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 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% 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 March 31, 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 $6,067,000 and $3,936,000, respectively.

Non-Hedging Activities. During the 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 March 31, 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 $1,426,000 and $2,597,000, respectively.

IX. Debt and Capital Lease

	March 31,		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		76,087
6.50% to 10.25% First Mortgage Bonds, due 2008 to 2029		112,386		112,421
Capital lease due 2005 to 2007		102		117
		1,073,340		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 bank loans due 2007		255,626		258,433
Net premiums on long-term debt		14,077		14,688
		1,187,131		1,190,549

Total consolidated debt and capital lease		2,260,471		2,163,939
Less current portion		76,985		89,650
Less fair value swaps of Panhandle Energy		6,067		3,936
Total consolidated long-term debt and capital lease	$	2,177,419	$	2,070,353

The Company has $2,260,471,000 of long-term debt recorded at March 31, 2005. Debt of $1,920,480,000, including net premiums of $14,077,000 and unamortized interest rate swaps of $6,067,000, is at fixed rates ranging from 2.75% to 10.25%, and the Company also has floating rate debt, including notes payable, totaling $459,991,000 bearing an average rate of 3.82% as of March 31, 2005. The variable rate bank loans are unsecured with the exception of the $255,626,000 Panhandle Energy bank loans that are fully collateralized by the Trunkline LNG assets.

As of March 31, 2005, the Company has scheduled debt payments of $76,985,000, $381,626,000, $301,648,000, $301,646,000, $61,998,000 and $1,122,491,000 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 Company 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 Company are direct obligations of Southern Union Company, 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 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 carries a variable interest rate that is tied to either the LIBOR or prime interest rates at the Company’s option. The interest rate spread over the LIBOR is currently LIBOR plus 105 basis points. As of March 31, 2005, a balance of $76,087,000 was outstanding on the 2002 Term Note at an effective interest rate of 3.93%. The Company repaid $30,000,000 under the 2002 Term Note on April 15, 2005. Principal repayments of $5,000,000 and $41,087,000 are due on August 15, 2005 and August 26, 2005, respectively. The Company expects to repay the balance of the 2002 Term Note with borrowings under the Long-Term Facility. No additional draws can be made on the 2002 Term Note.

Panhandle Refinancing. On April 29, 2005, Panhandle Energy refinanced the outstanding LNG bank loans of $255,626,000, due 2007, for the same amount and term. The new notes have substantially the same characteristics of the old notes with the exception of the following primary differences: (i) the assets of Trunkline LNG are not pledged as collateral; (ii) Panhandle Energy and Trunkline LNG each severally provided a guarantee for the notes; and (iii) the interest rate is tied to the rating of Panhandle Energy’s unsecured funded debt.

On March 12, 2004, Panhandle Energy issued $200,000,000 of its 2.75% Senior Notes due 2007, the proceeds of which were used 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. A portion of the remaining net proceeds was also used to repay the remaining $52,455,000 principal amount of Panhandle Energy’s 7.875% Senior Notes due 2004 that matured on August 15, 2004.

X. Notes Payable

On May 28, 2004, the Company entered into a new five-year long-term credit facility in the amount of $400,000,000 (the Long-Term Facility) that matures on May 29, 2009. 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 March 31, 2005, the commitment fees were an annualized 0.15%. A balance of $120,000,000 and $292,000,000 was outstanding under the Company’s credit facilities at an effective interest rate of 3.62% and 3.20% at March 31, 2005 and December 31, 2004, respectively. As of April 29, 2005, there was a balance of $70,000,000 outstanding under the Long-Term Facility.

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 common equity offering and sale of its equity units on such dates, as required under the terms of the Bridge Loan agreement.

XI. Employee Benefits

Components of Net Periodic Benefit Cost. Net periodic benefit cost for the three months ended March 31, 2005 and 2004 includes the following components:

	Pension Benefits						Post-retirement Benefits
	2005			2004			2005			2004

Service cost	$	2,003		$	1,738		$	1,233		$	913
Interest cost		5,555			5,586			2,344			1,975
Expected return on plan assets		(6,047	)		(5,244	)		(646	)		(419	)
Amortization of prior service cost		328			263			(51	)		19
Recognized actuarial loss		2,525			1,906			491			144
Curtailment recognition		381			--			--			--
Settlement recognition		(84	)		(119	)		--			--
Net periodic benefit cost	$	4,661		$	4,130		$	3,371		$	2,632

Employer Contributions. For the three months ended March 31, 2005, approximately $1,303,000 and $803,000 contributions were made to the Company’s pension plans and post-retirement 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 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, 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.

XII. Taxes on Income

Income tax expense during the quarter ended March 31, 2005 was $39,852,000. The Company's 2005 estimated annual consolidated federal and state effective income tax rate (Estimated EITR) was 30% as of March 31, 2005. The 2004 Estimated EITR was 38% as of March 31, 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; and (ii) the recognition of an 80% dividend received deduction on dividends expected to be received from Citrus during 2005.

Southern Union is in the process of completing an income tax project previously initiated to assess the timing and amount of temporary differences that may have accumulated over the years. The Company believes that this study will be completed in the second quarter of 2005. The analysis required in completing this project may identify deferred income tax assets or liabilities that should be reversed to decrease or increase income tax expense, respectively. Management does not believe that the effect of such reversals will have a material effect on the Company's results of operations.

XIII. Regulation and Rates

Missouri Gas Energy. On September 21, 2004, the Missouri Public Service Commission (MPSC) issued a rate order authorizing Missouri Gas Energy (MGE) to increase 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 should help stabilize revenue streams and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between customers and the Company.

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 directing the matter back 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 only 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 can not currently predict the outcome of this matter.

Panhandle Energy. In December 2002, the Federal Energy Regulatory Commission (FERC) approved a Trunkline LNG certificate application to expand the Lake Charles facility 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 increase terminal storage capacity to 9 Bcf from the current 6.3 Bcf. BG LNG Services has contract rights for the .57 Bcf per day of additional capacity. Construction on the Trunkline LNG expansion project (Phase I) commenced in September 2003 and is expected to be completed at an estimated cost totaling $137,000,000, plus capitalized interest, by the end of 2005. On September 17, 2004, as modified on September 23, 2004, the FERC approved Trunkline LNG’s further incremental LNG expansion project (Phase II). Phase II is estimated to cost approximately $77,000,000, plus capitalized interest, and would increase the LNG terminal sustainable send out capacity to 1.8 Bcf per day. Phase II has an expected in-service date of mid-2006. BG LNG Services has contracted for all the proposed additional capacity, subject to Trunkline LNG achieving certain construction milestones in the expansion of this facility. Approximately $150,000,000 and $127,000,000 of costs are included in the line item Construction Work In Progress for the expansion projects at March 31, 2005 and December 31, 2004, respectively.

In February 2004, Trunkline filed an application with the FERC to request approval of a 30-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal. Trunkline’s filing was approved on September 17, 2004, as modified on September 23, 2004. 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. On November 5, 2004, Trunkline filed an amended application with the FERC to change the size of the pipeline from 30-inch diameter to 36-inch diameter to better position Trunkline to provide transportation service for expected future LNG volumes and increase operational flexibility. The amendment was approved by FERC on February 11, 2005. The Trunkline natural gas pipeline loop associated with the LNG terminal is estimated to cost $50,000,000, plus capitalized interest. Approximately $23,000,000 and $21,000,000 of costs are included in the line item Construction Work In Progress for this project at March 31, 2005 and December 31, 2004, respectively.

XIV. Commitments and Contingencies

Environmental.

The Company is subject to federal, state and local laws and regulations relating to the protection of the environment. These evolving laws and regulations may require expenditures over a long period of time to con-trol environmental impacts. The Company has established 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 an 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.

The Company is investigating the possibility that the Company or predecessor companies may have been associated with Manufactured Gas Plant (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. At the present time, 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 Missouri Gas Energy. In addition, the New England Division 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 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 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 submission of these assessments to MDNR, MGE was required by MDNR to initiate remediation of Station A. Following the selection of a qualified contractor in a competitive bidding process, the Company began remediation of Station A in the first calendar quarter of 2003. The project was completed 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. However, MDNR may require additional investigation and possible remediation on Station A-North and on the railroad right-of-way adjacent to Station A. 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. An 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 at the site above the action levels specified in Missouri guidance documents. In a letter dated January 28, 2004, MDNR indicated that the MDNR would provide MGE a final version of the Missouri Risk-Based Corrective Action (MRBCA) process. On April 28, 2004, MDNR provided MGE with information regarding the MRBCA process, and requested a work plan on the St. Joseph site within 60 days of MGE’s receipt of this information. 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 is awaiting a response from MDNR. Part of the cost of the investigation should be recoverable by the Petroleum Storage Tank Insurance Fund.

New England Gas Company (NEGC).

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). Following the acquisition, environmental remediation at the site was temporarily suspended. During this suspension, the Company requested certain modifications to the 1999 Remedial Action Work Plan from RIDEM. After receiving approval to some of the requested modifications to the 1999 Remedial Action Work Plan, environmental work was reinitiated in April 2002, by a qualified contractor selected in a competitive bidding process. 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. Until NEGC receives a closure letter from RIDEM, it is unclear what, if any, additional investigation or remediation will be necessary.

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 a MGP in the early 1900s in Providence, Rhode Island. Subsequent to its use as a MGP, this site was operated for over eighty 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 twenty percent (20%) of the costs related to the investigation. To date, approximately $300,000 has been spent on environmental assessment work at this site. Until RIDEM provides its final response to the investigation, and the Company knows its ultimate responsibility respective 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 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 the RIDEM. Following the performance of a site investigation, NEGC submitted a Site Investigation Report in December 2003 to RIDEM. On April 15, 2004, NEGC obtained verbal approval from RIDEM to conduct additional investigation activity at the site. The results of the investigation are pending completion of the report.

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 (Work Plan) and subsequently perform a Site Investigation of the Bay Street Area. Without admitting responsibility or accepting liability, NEGC agreed to perform the activities requested. After receiving approval from RIDEM on a Work Plan, 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.

On May 2, 2005, the Company was served with a complaint filed 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 properties and emotional stress in an unspecified amount. The Company will vigorously defend against such lawsuit. In addition, two former residents of the area filed a tort action on August 20, 2003, against NEGC alleging personal injury to the plaintiffs. This litigation has not been served on the Company. The Company also received a demand letter dated July 1, 2004, sent by lawyers on behalf of the owners of a property in the Bay Street Area. This demand in the amount of $4,000,000 alleges property damage and personal injury.

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 to identify other potentially responsible parties associated with the fill materials and the waste disposal.

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. On November 25, 2003, MADEP issued a Notice of Responsibility letter to NEGC. Based upon the Phase I filing, NEGC is required to file a Phase II report with MADEP by September 18, 2005, to complete the site characterization.

66 Fifth Street, Fall River, Massachusetts Site - In a letter dated March 11, 2003, MADEP provided NEGC 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 Immediate Response Action (IRA) Work Plan in May 2003. The IRA Report was submitted to MADEP in July 2003. Investigation work performed to date indicates that cyanide concentrations at the down gradient properties are unrelated to the NEGC property at 66 Fifth Street. As required by MADEP, NEGC will submit a Phase II Risk Assessment and Site Closure Report. It is 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 the MADEP, the Company submitted an Immediate Response Action Plan (IRAP) to the MADEP on July 26, 2004. The Company’s IRAP proposes an investigation to determine whether or not coal gasification related material was historically dumped in the State Avenue Area.

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). Blackstone Valley Electric Company v. Stone & Webster, Inc., Stone & Webster Engineering Corporation, Stone & Webster Management Consultants, Inc. and Valley Gas Company, C. A. No. 94-10178JLT, United States District Court, District of Massachusetts. 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 United States Environmental Protection Agency (EPA) (Commonwealth of Massachusetts v. Blackstone Valley Electric Company, 67 F.3d 981 (1995)). The requested rulemaking concerned the question of whether or not 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 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 (merged in May 2000 with Narragansett Electric Company, a subsidiary of National Grid) have received letters of responsibility from the 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) in which Valley Gas Company and Blackstone agreed to share equally the expenses for 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 between 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 National Grid, parent company of Narragansett Electric Company, and representatives of the 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 a recent incident involving the release of mercury stored in a NEGC facility in Pawtucket, Rhode Island. On October 19, 2004, New England Gas Company discovered that a NEGC facility had been broken into and that mercury had been spilled both inside a building and in 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.

PG Energy.

Pennsylvania Sites - - During 2002, PG Energy received inquiries from the Pennsylvania Department of Environmental Protection (PADEP) pertaining to three Pennsylvania former MGP sites located in Scranton, Bloomsburg and Carbondale. 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 the 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. Thereafter, PG Energy is required to perform additional assessment and remediation activity as is deemed to be necessary based upon the results of the initial assessments.

Panhandle Energy Environmental Matters.

Panhandle Energy has previously identified environmental impacts at certain sites on its gas transmission systems and has undertaken cleanup programs at those sites. These impacts resulted from (i) the past use of lubricants containing polychlorinated bi-phenyls (PCBs) in compressed air systems; (ii) the past use of paints containing PCBs; (iii) the prior use of wastewater collection facilities; and (iv) other on-site disposal areas. Panhandle Energy communicated with EPA and appropriate state regulatory agencies on these matters, and has developed and implemented 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 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 an EPA-approved process to remediate this PCB contamination in accordance with federal, state and local regulations. Sixteen sites have been decontaminated per the EPA approved process as prescribed in the EPA regulations.

At some locations, PCBs have been identified in paint that was applied many years ago. In accordance with 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 an EPA approved manner.

The Illinois Environmental Protection Agency (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 percent. Panhandle Energy and 21 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 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 EPA is expected to issue special notice letters and has begun the process of listing the site on the National Priority List. Panhandle Energy and three of the other non-affiliated parties associated with the Pierce Oil Springfield site met with the EPA and Illinois EPA regarding this issue. Panhandle Energy was given no indication as to when the listing process was to be completed. Panhandle Energy has also submitted a Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) 104e data request from the US EPA Region V regarding the second Pierce Waste Oil site known as the Dunavan site, located in Oakwood Illinois. Panhandle Energy’s response showed that waste oil generated at Panhandle Energy facilities was shipped to the Dunavan Oil site in Oakwood Illinois, resulting in Panhandle Energy becoming a potentially responsible party at such site.

Based on information available at this time, 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 EPA issued a final rule on regional ozone control that requires Panhandle Energy to place controls on certain large internal combustion engines in five midwestern states. The part of the rule that affects Panhandle Energy was challenged in court by various states, industry and other interests, including 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 EPA’s rule, but agreed with INGAA’s position and remanded to the EPA the sections of the rule that affected Panhandle Energy. The final rule was promulgated by the EPA in April 2004. The five midwestern states have one year to promulgate state laws and regulations to address the requirements of this rule. Based on an 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 impacts 20 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.

In 2002, the Texas Commission on Environmental Quality enacted the Houston/Galveston State Implementation Plan (SIP) regulations requiring reductions in NOx emissions in an eight-county area surrounding Houston. Trunkline’s Cypress compressor station is affected and may require 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 and operated by Panhandle Energy. These two rules affect 2 Company facilities in Texas at an estimated cost of approximately $14,000,000 for capital improvements through March 2007, based on current projections.

The EPA promulgated various Maximum Achievable Control Technology (MACT) 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 of 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 20 internal combustion engines subject to the rules. It is expected that compliance with these regulations will cost an estimated $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 Commission 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 Commission. 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 October 2005.

Southwest Gas Litigation.

During 1999, several actions were commenced in federal courts by persons involved in competing efforts to acquire Southwest Gas Corporation (Southwest). All of these actions eventually were transferred to the U.S. District Court for the District of Arizona, consolidated and lodged with Judge Roslyn Silver. As a result of summary judgments granted, there were no claims allowed against Southern Union. The trial of Southern Union’s claims against the sole-remaining defendant, former Arizona Corporation Commissioner James Irvin, was concluded on December 18, 2002, with a jury award to Southern Union of nearly $400,000 in actual damages and $60,000,000 in punitive damages against former Commissioner Irvin. The District Court denied former Commissioner Irvin’s motions to set aside the verdict and reduce the amount of punitive damages. Former Commissioner Irvin has appealed to the Ninth Circuit Court of Appeals (Ninth Circuit). Oral argument is scheduled before the Ninth Circuit on May 10, 2005. A decision on the appeal by the Ninth Circuit is expected in 2005. The Company intends to vigorously pursue collection of the award. With the exception of ongoing legal fees associated with the collection of damages from former Commissioner Irvin, the Company believes that the results of the above-noted Southwest litigation and any related appeals will not have a material adverse effect on the Company's financial condition, results of operations or cash flows.

Other.

In 1993, the U.S. Department of the Interior announced its intention to seek, through its Minerals Management Service (MMS) additional royalties from gas producers as a result of payments received by such producers in connection with past take-or-pay settlements, buyouts, and buy downs of gas sales contracts with natural gas pipelines. Southern Union Exploration Company (SX, the Company’s former exploration and production subsidiary) has 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 (MMS Docket No. MMS-94-0184-IND). This claim has been on appeal to the Director of the MMS; the MMS has stayed the requirement that SX pay the claim pending the outcome of the appeal. The amounts claimed by the MMS, which involve leases on land owned by the Jicarilla Apache tribe, still have not been quantified fully. SX has also been issued, by the MMS Royalty Valuation Chief, an Order to Perform Major Portion Pricing and Dual Accounting on SX’s leases for the period from 1984 until 1995. SX has appealed the Order to the Director of the MMS. SX believes that it has several defenses to the Order to Perform. The amounts that may be claimed still have not been quantified fully. 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, Panhandle Eastern Pipe Line and Trunkline with respect to certain producer contract settlements may be contractually required to reimburse or, in some instances, to indemnify producers 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 which 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. A similar action has also been filed against a number of companies, including Panhandle Energy, in Kansas District Court. 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 suit vigorously.

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.

Commitments.

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

XV. 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: Missouri Gas Energy, PG Energy and New England Gas Company. 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 Alternate Energy Corporation provided energy consulting services. None of these businesses 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 is earnings before interest and taxes (EBIT) beginning January 1, 2005. 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) available for 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 months ended March 31, 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 months ended March 31, 2005 and 2004.

	Three Months Ended
	March 31,
	2005			2004
Revenues from external customers:
Distribution	$	631,056		$	635,384
Transportation and Storage		135,400			138,169
Total segment operating revenues		766,456			773,553
All Other		1,100			1,016
Total consolidated operating revenues	$	767,556		$	774,569

Depreciation and amortization:
Distribution	$	15,397		$	14,192
Transportation and Storage (1)		15,367			11,954
Total segment depreciation and amortization		30,764			26,146
All Other		154			141
Corporate		393			132
Total consolidated depreciation and amortization	$	31,311		$	26,419

Earnings from unconsolidated investments:
Distribution	$	--		$	--
Transportation and Storage		15,385			10
Total segment earnings from unconsolidated investments		15,385			10
All Other		(44	)		(12	)
Total consolidated earnings from unconsolidated investments	$	15,341		$	(2	)

Other income (expense):
Distribution	$	939		$	1,408
Transportation and Storage		336			704
Total segment other income, net		1,275			2,112
All Other		--			477
Corporate		(4,945	)		(1,126	)
Total consolidated other income, net	$	(3,670	)	$	1,463

Segment performance:
Distribution EBIT	$	90,149		$	85,028
Transportation and Storage EBIT		78,235			69,678
Total segment EBIT		168,384			154,706
All Other		(27	)		(2,251	)
Corporate		(1,104	)		(639	)
Interest		(35,205	)		(31,055	)
Federal and state income taxes		(39,852	)		(45,394	)
Net earnings	$	92,196		$	75,367

Expenditures for long-lived assets:
Distribution	$	12,381		$	13,257
Transportation and Storage		34,633			25,346
Total segment expenditures for long-lived assets		47,014			38,603
All Other		221			768
Corporate		3,825			3,960
Total consolidated expenditures for long-lived assets	$	51,060		$	43,331

		March 31,			December 31,
		2005			2004
Total assets:
Distribution	$	2,383,349		$	2,448,750
Transportation and Storage		3,011,558			2,957,880
Total segment assets		5,394,907			5,406,630
All Other		40,172			40,319
Corporate		135,564			121,340
Total consolidated assets	$	5,570,643		$	5,568,289

(1) Depreciation and amortization reflected herein for the three months ended March 31, 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 December 31, 2003 Form 10-K. 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 three months ended March 31, 2004.

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 footnotes to help provide an understanding of Southern Union’s financial condition, changes in financial condition and results of operations. The following section includes an overview of Southern Union’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 Southern Union’s liquidity and capital resources, and quantitative and qualitative disclosures about market risk and other matters.

Overview

Southern Union Company (Southern Union and together with its subsidiaries, the Company) 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 (TWP) 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 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, PG Energy and New England Gas Company, the Company serves over 967,000 natural gas end-user customers in Missouri, Pennsylvania, Massachusetts and Rhode Island.

On November 17, 2004, CCE Holdings, a joint venture in which Southern Union owns a 50% interest, acquired 100% of the equity interests of CrossCountry Energy from Enron 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 (TWP) and has a 50% interest in Citrus Corp. (Citrus) - which, in turn, owns 100% of Florida Gas Transmission Company (FGT). 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 Company’s reportable segments include the Distribution segment and the Transportation and Storage segment. Beginning January 1, 2005, segment results of operations are presented on an Earnings Before Interest and Taxes (EBIT) basis, which 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. The Company defines EBIT as net earnings (loss) available for 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. For additional segment reporting information, see Note XV - 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 for the three months ended March 31, 2005 and 2004:

	Three Months Ended
	March 31,
	2005			2004
	*(thousands of dollars)*
EBIT:
Distribution segment	$	90,149		$	85,028
Transportation and storage segment		78,235			69,678
All other		(27	)		(2,251	)
Corporate		(1,104	)		(639	)
Total EBIT		167,253			151,816
Interest		(35,205	)		(31,055	)
Earnings before income taxes		132,048			120,761
Federal and state income taxes		39,852			45,394
Net earnings		92,196			75,367
Preferred stock dividends		(4,341	)		(4,341	)
Net earnings available for common shareholders	$	87,855		$	71,026

Consolidated Results -- Three Months Ended March 31, 2005 Compared to 2004. The Company recorded net earnings available for common shareholders of $87,855,000 ($.86 per diluted share, hereafter referred to as per share) for the three months ended March 31, 2005 compared with $71,026,000 ($.92 per share) for the same period in 2004. The $16,829,000 increase in net earnings available for common shareholders was primarily due to the following:

·	a $5,121,000 increase in EBIT from the Distribution segment (see Business Segment Results - Distribution Segment);

·	a $8,557,000 increase in EBIT from the Transportation and Storage Segment (see Business Segment Results - Transportation and Storage Segment);

·	a $2,224,000 increase in EBIT from subsidiary operations included in the All Other category (see All Other Operations.); and

·	a $5,542,000 decrease in income tax expense (see Federal and State Income Taxes).

The above items were partially offset by the following:

·	a $465,000 decrease in EBIT from Corporate operations (see Corporate); and

·	a $4,150,000 increase in interest expense (see Interest Expense).

All Other Operations. EBIT from subsidiary operations included in the All Other category for the three months ended March 31, 2005 increased by $2,224,000, or 99%, to a loss of $27,000. The increase in EBIT primarily reflects a $2,985,000 charge recorded by PEI Power Corporation in 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 March 31, 2005 decreased by $465,000, or 73%, to a loss of $1,104,000. The decrease in Corporate EBIT primarily relates to charges of $4,508,000 to: (i) reserve for an other-than-temporary impairment of the Company’s investment in Advent; and (ii) record a liability for the guarantee by a subsidiary of the Company of a line of credit between Advent and a bank. These charges were partially offset by the impact of the direct allocation and recording of various services provided by Corporate to CCE Holdings in 2005 which were not applicable in 2004 due to the timing of the Company’s investment in CCE Holdings.

Interest Expense. Total interest expense for the three months ended March 31, 2005 increased by $4,150,000, or 13%, to $35,205,000. The increase was primarily attributable to $3,113,000 of interest expense recorded in 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, $571,000 of increased interest expense recorded in 2005 related to the Company’s 4.375% senior notes (see Note VII - Stockholders’ Equity) and $1,050,000 of increased interest expense on short-term debt as discussed below. These increases were partially offset by lower interest expense on Panhandle Energy’s debt of $307,000 (net of amortization of debt premiums established in purchase accounting related to the Panhandle Energy acquisition), decreased interest expense $129,000 on the $311,087,000 bank note (the 2002 Term Note) and decreased interest expense of $22,000 related to other long-term debt of the Company. The average rate of interest on all debt increased from 5.1% in 2004 to 5.4% in 2005.

Interest expense on short-term debt for the three months ended March 31, 2005 increased by $1,050,000, or 121%, to $1,920,000, primarily due to the increase in the average amount of short-term debt outstanding from $194,583,000 during 2004 to $204,409,000 during 2005 and the increase in the average rate of interest on short-term debt from 1.8% in 2004 to 3.3% in 2005.

Federal and State Income Taxes. Federal and state income tax expense for the three months ended March 31, 2005 and 2004 was $39,852,000 and $45,394,000, respectively. The Company's 2005 estimated annual consolidated federal and state effective income tax rate (Estimated EITR) was 30% as of March 31, 2005. The 2004 Estimated EITR was 38% as of March 31, 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; and (ii) the recognition of an 80% dividend received deduction on dividends expected to be received from Citrus during 2005 (see Note XII -Taxes On Income).

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: Missouri Gas Energy, PG Energy and New England Gas Company. Collectively, the utility divisions serve over 967,000 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 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 months ended March 31, 2005 and 2004:

	Three Months Ended
	March 31,
	2005			2004
	*(thousands of dollars)*
Financial Results
Operating revenues	$	631,056		$	635,384
Cost of gas and other energy		(448,314	)		(454,587	)
Revenue-related taxes		(22,239	)		(21,951	)
Net operating revenues, excluding depreciation and amortization		160,503			158,846
Operating expenses:
Operating, maintenance, and general		49,394			54,525
Depreciation and amortization		15,397			14,192
Taxes other than on income and revenues		6,502			6,509
Total operating expenses		71,293			75,226
Operating income		89,210			83,620
Other income, net		939			1,408
EBIT	$	90,149		$	85,028

Operating Information
Gas sales volumes in millions of cubic feet (MMcf)		53,463			56,722
Gas transported volumes in MMcf		19,002			19,790
Weather:
Degree days:
Missouri Gas Energy service territories		2,434			2,595
PG Energy service territories		3,332			3,293
New England Gas Company service territories		3,021			3,062
Percent of 30-year measure:
Missouri Gas Energy service territories		90	%		96	%
PG Energy service territories		107	%		106	%
New England Gas Company service territories		104	%		105	%

Distribution Segment Results -- Three Months Ended March 31, 2005 Compared to 2004. The Distribution segment recorded EBIT of $90,149,000 for the three months ended March 31, 2005, which reflects a $5,121,000 increase in EBIT compared with the same period in 2004.

Operating Revenues. Operating revenues for the three months ended March 31, 2005 compared with the three months ended March 31, 2004 decreased $4,328,000, or 1%, to $631,056,000 while gas purchase and other energy costs decreased $6,273,000, or 1%, to $448,314,000. The decrease in both operating revenues and gas purchase costs between periods was primarily due to a 6% decrease in gas sales volumes to 53,463 million cubic feet (MMcf) in 2005 from 56,722 MMcf in 2004, which was partially offset by a 5% increase in the average cost of gas from $8.01 per thousand cubic feet (Mcf) in 2004 to $8.39 per Mcf in 2005. The decrease in gas sales volumes is primarily due to warmer weather in 2005 as compared with 2004 in two out of three of the Company’s service territories. The increase in the average cost of gas is due to increases in the average spot market prices throughout the Company’s distribution system as a result of current competitive pricing occurring within the entire energy industry. Operating revenues in 2005 were also impacted by the $22,370,000 annual increase to base revenues granted to Missouri Gas Energy, 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, while 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.

Net Operating Revenues. Net operating revenues for the three months ended March 31, 2005 increased by $1,657,000, to $160,503,000. 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 Missouri Gas Energy, as previously noted. Sales volumes in 2005 were negatively impacted by the warmer weather in 2005 as compared with 2004, as previously noted.

Operating Expenses. Operating, maintenance and general expenses for the three months ended March 31, 2005 decreased $5,131,000, or 9%, to $49,394,000. Operating expenses were impacted by $2,795,000 of decreased bad debt expense resulting from a lower level of aged customer receivables, $1,964,000 of decreased employee payroll and benefit costs, and $1,322,000 of decreased outside service, information technology and subcontract labor costs. These reductions were partially offset by $1,474,000 of increased outside service fees related to environmental matters.

As of March 31, 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 can impact the operating results of this segment during the remainder of 2005.

Depreciation and amortization expense for the three months ended March 31, 2005 increased $1,205,000 to $15,397,000. The increase was primarily due to normal growth in plant.

Supplemental Operating Information. The following table sets forth additional gas throughput and related information for the Company's Distribution segment for the three months ended March 31, 2005 and 2004:

	Three Months Ended
	March 31,
	2005			2004

Average number of customers:
Residential		856,954			853,825
Commercial		106,181			105,455
Industrial and irrigation		427			437
Public authorities and other		401			385
Total average customers served		963,963			960,102
Transportation customers		3,065			2,694
Total average gas sales and transportation customers		967,028			962,796

Gas sales in MMcf:
Residential		39,184			42,239
Commercial		16,034			17,238
Industrial and irrigation		837			748
Public authorities and other		164			162
Gas sales billed		56,219			60,387
Net change in unbilled gas sales		(2,756	)		(3,665	)
Total gas sales		53,463			56,722
Gas transported		19,002			19,790
Total gas sales and gas transported		72,465			76,512

Gas sales revenues (thousands of dollars):
Residential	$	461,266		$	449,506
Commercial		179,837			175,513
Industrial and irrigation		8,832			7,510
Public authorities and other		1,668			1,509
Gas revenues billed		651,603			634,038
Net change in unbilled gas sales revenues		(35,999	)		(17,401	)
Total gas sales revenues		615,604			616,637
Gas transportation revenues		14,007			12,111
Other revenues		1,445			6,636
Total operating revenues	$	631,056		$	635,384



	Three Months Ended
	March 31,
		2005			2004
Gas sales revenue per thousand cubic feet billed:
Residential	$	11.77		$	10.64
Commercial		11.22			10.18
Industrial and irrigation		10.55			10.04
Public authorities and other		10.17			9.31

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, LLC (CCE Holdings), Southern Union has an interest in and operates the Transwestern Pipeline and Florida Gas Transmission Company interstate pipelines. TWP 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. Panhandle Energy’s and CCE Holdings’ operations are regulated as to rates and other matters by the 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 months ended March 31, 2005 and 2004:

	Three Months Ended
	March 31,
	2005		2004
	*(thousands of dollars)*
Financial Results
Reservation revenue	$	100,587	$	101,212
LNG terminalling revenue		13,208		13,762
Commodity revenue		19,433		20,648
Other revenue		2,172		2,547
Total operating revenues		135,400		138,169
Operating expenses:
Operating, maintenance, and general		50,183		49,725
Depreciation and amortization (1)		15,367		11,954
Taxes other than on income and revenues		7,336		7,526
Total operating expenses		72,886		69,205
Operating income		62,514		68,964
Earnings from unconsolidated investments		15,385		10
Other income, net		336		704
EBIT	$	78,235	$	69,678

Operating Information
Gas transported in trillions of British thermal units (Tbtu)		350		352

Transportation and Storage Segment Results -- Three Months Ended March 31, 2005 Compared to 2004. The Transportation and Storage segment recorded EBIT of $78,235,000 for the three months ended March 31, 2005, which reflects an $8,557,000 increase in EBIT compared with the same period in 2004.

Operating Revenues. Operating revenues for the three months ended March 31, 2005 compared with the three months ended March 31, 2004 decreased $2,769,000, or 2%, to $135,400,000. Operating revenues were impacted by lower commodity revenues of $1,215,000 due to a reduction in commodity throughput volumes of one percent, associated with a two percent decrease of heating degree days, as well as a lower market value for interruptible service, partially offset by higher parking revenue activity. Commodity revenues are dependent upon a number of variable factors, including weather, storage levels, and customer demand for firm, interruptible and parking services. In addition, reservation revenue decreased $625,000 primarily due to certain contract expirations on Trunkline during the latter part of 2004 and the replacement thereof at lower average reservation rates. LNG terminalling revenue decreased $554,000 primarily due to reduced LNG volumes received in 2005.

Operating Expenses. Operating, maintenance and general expenses for the three months ended March 31, 2005 increased $458,000, or 1%, to $50,183,000. Such increase was due to the recovery of previously underrecovered fuel, net of $1,103,000 in 2004 and higher pipeline transportation expenses of $408,000 primarily due to a new contract, partially offset by reduced administrative expenses of $589,000 primarily associated with the workforce reduction in 2004, reduced contract storage expenses and LNG power costs.

Depreciation and amortization expense for the three months ended March 31, 2005 increased $3,413,000 to $15,367,000 primarily due to the $3,193,000 purchase accounting adjustments recorded in 2004, as previously noted.

Earnings from Unconsolidated Investments. Earnings from unconsolidated investments for the three months ended March 31, 2005 and 2004 were $15,385,000 and $10,000, respectively. The increase in earnings from unconsolidated investments in 2005 is primarily due to $15,332,000 of earnings from CCE Holdings, which the Company acquired on November 17, 2004.

Liquidity and Capital Resources

Operating Activities. The seasonal nature of Southern Union’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 $231,888,000 for the three months ended March 31, 2005 compared with cash flows provided by operating activities of $246,802,000 for the same period in 2004. Cash flows provided by operating activities before changes in operating assets and liabilities for 2005 were $161,655,000 compared with $159,275,000 for 2004. Changes in operating assets and liabilities provided cash of $70,233,000 in 2005 and $87,527,000 in 2004. Working capital was positively impacted in 2005 by increases in deferred purchased gas costs, increases in taxes and other liabilities, and net changes in gas imbalances with customers compared to 2004. This benefit was offset by lower withdrawals from gas inventories, larger decreases in accounts payable and increases in accounts receivable, along with net uses of cash related to deferred charges and credits compared to the same period in 2004.

At March 31, 2005 and December 31, 2004, the Company’s primary source of liquidity included borrowings available under the Company’s credit facilities. On May 28, 2004, the Company entered into a new five-year long-term credit facility in the amount of $400,000,000 (the Long-Term Facility) that matures on May 29, 2009. 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 lines 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 March 31, 2005, the commitment fees were an annualized 0.15%. A balance of $120,000,000 and $292,000,000 was outstanding under the Company’s credit facilities at an effective interest rate of 3.62% and 3.20% at March 31, 2005 and December 31, 2004, respectively. As of April 29, 2005, there was a balance of $70,000,000 outstanding under the Long-Term Facility.

Investing Activities. Cash flows used in investing activities were $52,095,000 for the three months ended March 31, 2005 compared with $48,863,000 for the same period in 2004.

During the three months ended March 31, 2005 and 2004, the Company expended $51,060,000 and $43,331,000, respectively, for capital expenditures excluding acquisitions. The Transportation and Storage segment expended $34,633,000 and $25,346,000 for capital expenditures during the three months ended March 31, 2005 and 2004, respectively. Included in these capital expenditures were approximately $25,000,000 and $19,000,000 relating to the LNG terminal Phase I and Phase II expansions and the Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal in 2005 and 2004, respectively. The remaining capital expenditures for the respective periods primarily related to Distribution segment system replacement and expansion. Included in these capital expenditures were $2,098,000 and $1,150,000 for the Missouri Gas Energy Safety Program during the three months ended March 31, 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 and the Trunkline 36-inch diameter, 23-mile natural gas pipeline loop from the LNG terminal to be approximately $81,000,000 for the remainder of 2005 and approximately $10,000,000 in 2006, plus capitalized interest. These estimates were developed for budget planning purposes and are subject to revision.

Financing Activities. Cash flows used in financing activities were $162,354,000 for the three months ended March 31, 2005 compared with $147,165,000 for the same period in 2004. Financing activity cash flow changes were primarily due to the net impact of acquisition financing, repayment 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 March 31, 2005 was 55.3%, compared with 65.5% at March 31, 2004, respectively. The Company’s effective debt cost rate under the current debt structure was 5.91% (which includes interest and the amortization of debt issuance costs and redemption premiums on refinanced debt) as of March 31, 2005.

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

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.

Other Matters

Customer Concentrations. In the Transportation and Storage segment, aggregate sales to Panhandle Energy’s top 10 customers accounted for 68% of segment operating revenues and 12% of the Company’s total operating revenues for the three months ended March 31, 2005. This included sales to ProLiance Energy, LLC, a nonaffiliated local distribution company and gas marketer, which accounted for 18% of segment operating revenues, sales to BG Energy Holdings Limited, a nonaffiliated gas marketer, which accounted for 13% of segment operating revenues and sales to Ameren Corporation, which accounted for 13% 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 three months ended March 31, 2005.

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

Regulatory. The majority of the Company's business activities are subject to various regulatory authorities. The Company's financial condition and results of operations have been and will continue to be dependent upon the receipt of adequate and timely adjustments in rates.

On September 21, 2004, the Missouri Public Service Commission issued a rate order authorizing Missouri Gas Energy to increase 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 should help stabilize revenue streams and implemented an incentive mechanism for the sharing of capacity release and off-system sales revenues between customers and the Company.

In December 2002, the Federal Energy Regulatory Commission (FERC) approved a Trunkline LNG certificate application to expand the Lake Charles facility 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 increase terminal storage capacity to 9 Bcf from the current 6.3 Bcf. BG LNG Services has contract rights for the .57 Bcf per day of additional capacity. Construction on the Trunkline LNG expansion project (Phase I) commenced in September 2003 and is expected to be completed at an estimated cost totaling $137,000,000, plus capitalized interest, by the end of 2005. On September 17, 2004, as modified on September 23, 2004, the FERC approved Trunkline LNG’s further incremental LNG expansion project (Phase II). Phase II is estimated to cost approximately $77,000,000, plus capitalized interest, and would increase the LNG terminal sustainable send out capacity to 1.8 Bcf per day. Phase II has an expected in-service date of mid-2006. BG LNG Services has contracted for all the proposed additional capacity, subject to Trunkline LNG achieving certain construction milestones in the expansion of this facility. Approximately $150,000,000 and $127,000,000 of costs are included in the line item Construction Work In Progress for the expansion projects at March 31, 2005 and December 31, 2004, respectively.

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 our 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 Securities and Exchange Commission 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 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; our or any of our subsidiaries debt securities ratings; the economic climate and growth in our 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.

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 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 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

We performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), and with the participation of personnel from our 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 Rule 13a-15(e) or Rule 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as March 31, 2005 and have communicated that determination to the Audit Committee of our Board of Directors.

Changes in Internal Controls.

Although, as previously disclosed and more fully discussed below, management has not completed its assessment of the Company’s internal control over financial reporting as of December 31, 2004, management is not aware of any change in Southern Union’s internal control over financial reporting that occurred during the quarter ended March 31, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Status of Management’s Report on Internal Control Over Financial Reporting.

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined as a process designed by, or under the supervision of, the Company’s principal executive officer and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management and other personnel, 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 and includes those policies that:

·	Pertain to the maintenance of records in reasonable detail to accurately and fairly reflect the transactions and dispositions of the assets of the Company;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

·	Provide reasonable assurance regarding the prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Securities Exchange Act Rules 13a-15(c) and 15d-15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Company to conduct an annual evaluation of the Company’s internal control over financial reporting and to provide a report on management’s assessment including a statement as to whether or not internal control over financial reporting is effective. Additionally, the Company is required to provide an attestation report of the Company’s independent registered public accountant on management’s assessment of our internal control over financial reporting.

In December 2004, the Company determined to change its fiscal year-end from June 30 to December 31. The Company’s change to a calendar year-end reporting period had the effect of accelerating, from June 30, 2005 to December 31, 2004, the first date for which the Company must comply with the requirements of Section 404. As previously disclosed in the Company’s Form 8-K and Form 10-K, filed December 31, 2004, and March 16, 2005, respectively, this accelerated timetable did not allow for timely completion of an evaluation of the Company’s internal control over financial reporting or the related testing of the Company’s internal control over financial reporting in order for management to complete its assessment of the effectiveness of the design and operation of internal control over financial reporting and for the Company’s independent registered public accounting firm to audit management’s assessment of the effectiveness of the Company’s internal control over financial reporting in time for filing with the Company’s Transition Report on Form 10-K for the six-month period ended December 31, 2004.

The evaluation of the Company’s internal control over financial reporting has been, and continues to be conducted under the direction of the Company’s senior management. The Company’s management is regularly discussing the results of its testing and any proposed improvements to its control environment with the Company’s Audit Committee.

The certifications required by (i) 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002 and furnished herewith as Exhibits 32.1 and 32.2 and (ii) Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, filed herewith as Exhibits 31.1 and 31.2, are qualified entirely by reference to the above discussion.

The Company will file an amendment to its Transition Report on Form 10-K to include (i) the reports of management and the Company’s independent registered public accounting firm as required by Section 404 of the Sarbanes-Oxley Act and (ii) revised certifications as required by Section 906 of the Sarbanes-Oxley Act and Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act. No assurances can be given that the Company’s completion of its evaluation of internal control, or related testing, will not result in the identification of internal control deficiencies or material weaknesses.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

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

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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SOUTHERN UNION COMPANY
	(Registrant)






Date May 10, 2005	By /S/ DAVID J. KVAPIL
	David J. Kvapil
	Executive Vice President and
	Chief Financial Officer (Principal
	Accounting Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXHANGE 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)) 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)

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

(c)

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: May 10, 2005

/s/ GEORGE L. LINDEMANN

George L. Lindemann

Chairman of the Board and

Chief Executive Officer

(principal executive officer)

Exhibit 31.2

CERTIFICATION PURSUANT TO

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

I, David J. Kvapil, certify that:

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

(a)

(b)

(c)

(a)

(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: May 10, 2005

/s/ DAVID J. KVAPIL

David J. Kvapil

Executive Vice President and

Chief Financial Officer

(principal financial officer)

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 March 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George L. Lindemann, Chairman of the Board 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, except as otherwise noted under Item 4 therein, 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 and

Chief Executive Officer

May 10, 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.

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 March 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David J. Kvapil, Executive 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, except as otherwise noted under Item 4 therein, 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/ DAVID J. KVAPIL

David J. Kvapil

Executive Vice President and

Chief Financial Officer

May 10, 2005