10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark one)
[ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 2005
or
[    ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from___________ to ___________
Commission file number   1-08246
SOUTHWESTERN ENERGY COMPANY
(Exact name of the registrant as specified in its charter)
Arkansas	71-0205415
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
(281) 618-4700
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year: if changed since last report)
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 and Exchange Act of 1934 during the preceding twelve 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:   X	No:
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes:   X	No:
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class	Outstanding at July 25, 2005
Common Stock, Par Value $0.10	73,531,593

PART I

FINANCIAL INFORMATION

1

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
		For the three months ended				For the six months ended
		June 30,				June 30,
		2005		2004		2005		2004
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	93,192	$	73,838	$	219,463	$	174,857
	Gas marketing		30,203		15,674		54,750		24,860
	Oil sales		7,428		4,008		13,539		8,342
	Gas transportation and other		1,640		2,907		5,764		8,158
			132,463		96,427		293,516		216,217
Operating Costs and Expenses:
	Gas purchases - utility		5,078		3,518		38,901		35,050
	Gas purchases - marketing		28,932		14,572		52,130		22,635
	Operating expenses		12,413		10,498		24,346		20,210
	General and administrative expenses		10,308		8,264		20,611		16,274
	Depreciation, depletion and amortization		23,009		17,091		43,256		32,617
	Taxes, other than income taxes		5,542		4,238		10,865		7,878
			85,282		58,181		190,109		134,664
Operating Income			47,181		38,246		103,407		81,553
Interest Expense:
	Interest on long-term debt		5,241		4,376		10,164		8,797
	Other interest charges		358		316		668		828
	Interest capitalized		(944)		(745)		(1,639)		(1,293)
			4,655		3,947		9,193		8,332
Other Income (Expense)			15		(868)		199		(547)
Income Before Income Taxes and Minority Interest			42,541		33,431		94,413		72,674
Minority Interest in Partnership			(315)		(431)		(408)		(830)
Income Before Income Taxes			42,226		33,000		94,005		71,844
Provision for Income Taxes - Deferred			15,412		12,210		34,570		26,582
Net Income		$	26,814	$	20,790	$	59,435	$	45,262
Earnings Per Share: (1)
	Basic		$0.37		$0.29		$0.82		$0.64
	Diluted		$0.36		$0.28		$0.79		$0.62
Weighted Average Common Shares Outstanding: (1)
	Basic		72,474,987		71,342,912		72,363,971		71,220,908
	Diluted		75,202,033		73,650,562		75,057,761		73,439,858
(1)  2004 restated to reflect a two-for-one stock split effected in June 2005.
The accompanying notes are an integral part of the financial statements.
2

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
			June 30,		December 31,
			2005		2004
			(in thousands)
Current Assets
	Cash		$	745	$	1,235
	Accounts receivable			60,895		86,268
	Inventories, at average cost			25,621		32,248
	Deferred income tax assets			16,100		3,600
	Other			6,093		7,634
		Total current assets		109,454		130,985
Investments				15,738		15,465
Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method			1,664,444		1,483,824
	Gas distribution systems			211,811		207,447
	Gas in underground storage			32,254		32,254
	Other			38,581		37,820
				1,947,090		1,761,345
	Less: Accumulated depreciation, depletion and amortization			820,277		777,189
				1,126,813		984,156
Other Assets				17,470		15,538
Total Assets			$	1,269,475	$	1,146,144
The accompanying notes are an integral part of the financial statements.
3

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
			June 30,		December 31,
			2005		2004
			(in thousands)
Current Liabilities
	Accounts payable		$	84,088	$	81,586
	Taxes payable			8,424		9,333
	Hedging liability - FAS No. 133			49,613		29,886
	Over-recovered purchased gas costs			9,839		1,412
	Other			11,615		11,483
		Total current liabilities		163,579		133,700
Long-Term Debt				328,100		325,000
Other Liabilities
	Deferred income taxes			226,763		203,996
	Other			51,025		23,912
				277,788		227,908
Commitments and Contingencies
Minority Interest in Partnership				12,074		11,859
Shareholders' Equity
	Common stock, $.10 par value; authorized 220,000,000 shares, issued 74,451,168 shares in 2005 and 2004 (1)			7,445		7,445
	Additional paid-in capital (1)			131,388		125,031
	Retained earnings			409,896		350,461
	Accumulated other comprehensive income (loss)			(50,334)		(19,816)
	Common stock in treasury, at cost, 964,815 shares at June 30, 2005 and 1,643,152 shares at December 31, 2004 (1)			(5,374)		(9,156)
	Unamortized cost of restricted shares issued under stock incentive plan, 617,662 shares at June 30, 2005 and 640,576 restricted shares at December 31, 2004 (1)			(5,087)		(6,288)
				487,934		447,677
Total Liabilities and Shareholders' Equity			$	1,269,475	$	1,146,144
(1)  2004 restated to reflect a two-for-one stock split effected in June 2005.
The accompanying notes are an integral part of the financial statements.
4

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the six months ended
			June 30,
			2005		2004
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	59,435	$	45,262
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		45,264		34,372
		Deferred income taxes		34,570		26,582
		Ineffectiveness of cash flow hedges		(531)		1,239
		Gain on sale of other property, plant & equipment		-		(1,534)
		Equity in (income) loss of NOARK partnership		(273)		545
		Minority interest in partnership		216		356
	Change in operating assets and liabilities:
		Accounts receivable		25,373		4,628
		Inventories		8,427		5,957
		Under/over-recovered purchased gas costs		6,834		(638)
		Accounts payable		(13,843)		6,482
		Taxes payable		(908)		(997)
		Other operating assets and liabilities		(173)		(1,781)
	Net cash provided by operating activities			164,391		120,473
Cash Flows From Investing Activities
	Capital expenditures			(176,981)		(124,234)
	Proceeds from sale of other property, plant & equipment			1,040		1,906
	Other items			(297)		(74)
	Net cash used in investing activities			(176,238)		(122,402)
Cash Flows From Financing Activities
	Payments on revolving long-term debt			(179,100)		(210,300)
	Borrowings under revolving long-term debt			182,200		209,500
	Debt issuance costs			(1,180)		(1,514)
	Change in bank drafts outstanding			5,743		898
	Proceeds from exercise of common stock options			3,694		3,154
	Net cash provided by financing activities			11,357		1,738
Decrease in cash				(490)		(191)
Cash at beginning of year				1,235		1,277
Cash at end of period			$	745		1,086
The accompanying notes are an integral part of the financial statements.
5

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
						Accumulated		Unamortized
			Additional			Other	Common	Restricted
	Common Stock		Paid-In		Retained	Comprehensive	Stock in	Stock
	Shares	Amount	Capital		Earnings	Income (Loss)	Treasury	Awards	Total
				(in thousands)
Balance at December 31, 2004	37,226	$3,723	$128,753		$350,461	($19,816)	($9,156)	($6,288)	$447,677
Comprehensive income:
Net Income	-	-	-		59,435	-	-	-	59,435
Change in value of derivatives	-	-	-		-	(30,518)			(30,518)
Total comprehensive income	-	-	-		-	-	-	-	28,917
Two-for-one stock split	37,226	3,722	(3,722)		-	-	-	-	-
Exercise of  stock options	-	-	6,218		-	-	3,846	-	10,064
Issuance of restricted stock	-	-	215		-	-	50	(265)	-
Cancellation of restricted stock	-	-	(76)		-	-	(114)	190	-
Amortization of restricted stock	-	-	-		-	-	-	1,276	1,276
Balance at June 30, 2005	74,452	$7,445	$131,388		$409,896	($50,334)	($5,374)	($5,087)	$487,934

RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
		For the three months ended				For the six months ended
		June 30,				June 30,
			2005		2004		2005		2004
			(in thousands)				(in thousands)
Balance, beginning of period		$	(58,832)	$	(19,517)	$	(19,816)	$	(12,520)
	Current period reclassification to earnings		7,688		4,946		8,927		7,641
	Current period change in derivative instruments		810		(9,630)		(39,445)		(19,322)
Balance, end of period		$	(50,334)	$	(24,201)	$	(50,334)	$	(24,201)
The accompanying notes are an integral part of the financial statements.
6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

June 30, 2005

(1)    BASIS OF PRESENTATION

      The financial statements included herein are unaudited; however, such information reflects all adjustments (consisting solely of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. The Company's significant accounting policies are summarized in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2004 (the "2004 Annual Report on Form 10-K").

    In June 2005, the Company distributed additional shares of its common stock in a two-for-one stock split that was declared by its board of directors in May 2005. All historical per share information in the financial statements and footnotes has been adjusted to reflect the two-for-one stock split.

(2)    GAS AND OIL PROPERTIES

    The Company utilizes the full cost method of accounting for costs related to its natural gas and oil properties. Under this method, all such costs (productive and nonproductive) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of this ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. At June 30, 2005, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At June 30, 2005, our standardized measure was calculated based upon quoted market prices of $7.02 per Mcf for Henry Hub gas and $56.50 per barrel for West Texas Intermediate oil, adjusted for market differentials. A decline in natural gas and oil prices from June 30, 2005 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

(3)    EARNINGS PER SHARE

    Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during each period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding the incremental number of shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock. All of the Company's outstanding options at June 30, 2005 (4,029,832 options with an average exercise price of $6.37) and June 30, 2004 (4,574,666 options with an average exercise price of $5.34) were included in the calculation of diluted shares. Restricted shares included in the calculation of diluted shares were 415,141 and

7

374,062 at June 30, 2005 and 2004, respectively. The number of options and the option prices, and the number of restricted shares for both 2004 and 2005 reflect the two-for-one stock split distributed in the second quarter of 2005.

(4)    DEBT

    Debt balances as of June 30, 2005 and December 31, 2004 consisted of the following:

	June 30,	December 31,
	2005	2004
	(in thousands)
Senior notes:
6.70% Series due December 2005	$ 125,000	$ 125,000
7.625% Series due 2027, putable at the holders' option in 2009	60,000	60,000
7.21% Series due 2017	40,000	40,000
	225,000	225,000
Other:
Variable rate (4.49% at June 30, 2005 and 3.66% at December 31, 2004) unsecured revolving credit arrangements	103,100	100,000
Total debt	$ 328,100	$  325,000

    In January 2005, the Company arranged a new $500 million five-year unsecured revolving credit facility that amended and restated its existing $300 million three-year credit facility that would have expired in January 2007 and replaced a smaller unsecured credit facility that would have matured at the same time. The interest rate on the new credit facility is calculated based upon the Company's debt rating and is currently 125 basis points over the current London Interbank Offered Rate (LIBOR). The revolving credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 60% of its total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. There are also restrictions on the ability of the Company's subsidiaries to incur debt. A t June 30, 2005, the Company's capital structure consisted of 40% debt (excluding its several guarantee of NOARK's obligations) and 60% equity, with a ratio of EBITDA to interest expense of 16.3, and the Company was in compliance with its debt agreements.

    The 6.70% senior notes in the table above are due December 2005. The Company currently intends to use its credit facility to repay these notes and, accordingly, these notes are classified as long-term based upon the Company's ability to fund them on a long-term basis.

8

(5)    DERIVATIVES AND RISK MANAGEMENT

    The Company applies Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended by FAS 137, FAS 138 and FAS 149 which requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement.

    At June 30, 2005, the Company's net liability related to its cash flow hedges was $80.8 million. Additionally, at June 30, 2005, the Company had recorded a net of tax cumulative loss to other comprehensive income (equity section of the balance sheet) of $49.3 million. The amount recorded in other comprehensive income will be relieved over time and taken to the income statement as the physical transactions being hedged occur. Assuming the market prices of futures as of June 30, 2005 remain unchanged, the Company would expect to transfer an aggregate loss of approximately $29.4 million from accumulated other comprehensive income to pre-tax earnings during the next 12 months. The changes in accumulated other comprehensive income (loss) related to derivatives were a gain of $13.4 million ($8.5 million after tax) and a loss of $7.4 million ($4.7 million after tax) for the three months ended June 30, 2005 and 2004, respectively, and losses of $48.4 million ($30.5 million after tax) and $18.5 million ($11.7 million after tax) for the six months ended June 30, 2005 and 2004, respectively. Additional volatility in earnings and other comprehensive income (loss) may occur in the future as a result of the application of FAS 133.

(6)    SEGMENT INFORMATION

    The Company applies Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information." The Company's reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of natural gas and crude oil. Revenues for the gas distribution segment arise from the transportation and sale of natural gas at retail. The marketing segment generates revenue through the marketing of both Company and third-party produced gas volumes.

    Summarized financial information for the Company's reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 to the financial statements in the Company's 2004 Annual Report on Form 10-K. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes is the sum of operating income, interest expense, other income (expense) and minority interest in partnership. The "Other" column includes items not related to the Company's reportable segments including real estate, pipeline operations and corporate items.

9

	Exploration
	And	Gas
	Production	Distribution	Marketing	Other		Total
	(in thousands)
Three months ended June 30, 2005:
Revenues from external customers	$  77,859	$  24,400	$  30,204	$    --		$  132,463
Intersegment revenues	9,181	33	62,098	112		71,424
Operating income (loss)	48,599	(2,361)	931	12		47,181
Depreciation, depletion and    amortization expense	21,286	1,688	11	24		23,009
Interest expense (1)	3,331	935	123	266		4,655
Provision (benefit) for income taxes (1)	16,422	(1,264)	300	(46)		15,412
Assets	1,038,399	156,561	27,830	46,685	(2)	1,269,475	(2)
Capital expenditures(3)	103,068	2,701	--	53		105,822
Three months ended June 30, 2004:
Revenues from external customers	$  56,389	$  22,986	$  15,674	$  1,378		$  96,427
Intersegment revenues	9,483	26	56,761	112		66,382
Operating income (loss)	37,452	(1,428)	811	1,411		38,246
Depreciation, depletion and    amortization expense	15,444	1,616	9	22		17,091
Interest expense (1)	2,533	1,103	77	234		3,947
Provision (benefit) for income taxes (1)	12,761	(975)	272	152		12,210
Assets	760,639	154,648	25,905	37,246	(2)	978,438	(2)
Capital expenditures(3)	66,428	1,241	1	532		68,202

Six months ended June 30, 2005:
Revenues from external customers	$ 151,707	$ 87,058	$ 54,751	$ --		$ 293,516
Intersegment revenues	17,876	126	116,616	224		134,842
Operating income	96,330	5,086	1,968	23		103,407
Depreciation, depletion and amortization expense	39,800	3,387	21	48		43,256
Interest expense (1)	6,441	2,030	197	525		9,193
Provision (benefit) for income taxes (1)	32,904	1,089	656	(79)		34,570
Assets	1,038,399	156,561	27,830	46,685	(2)	1,269,475	(2)
Capital expenditures(3)	181,523	4,783	1	376		186,683
Six months ended June 30, 2004:
Revenues from external customers	$ 105,634	$ 84,189	$ 24,860	$ 1,534		$ 216,217
Intersegment revenues	19,309	82	108,835	224		128,450
Operating income	70,881	7,382	1,698	1,592		81,553
Depreciation, depletion and amortization expense	29,336	3,217	18	46		32,617
Interest expense (1)	5,439	2,275	140	478		8,332
Provision for income taxes (1)	23,913	1,884	577	208		26,582
Assets	760,639	154,648	25,905	37,246	(2)	978,438	(2)
Capital expenditures(3)	123,011	3,180	1	647		126,839

(1)    Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as debt and income tax expense are incurred at the corporate level.

(2)    Other assets include the Company's equity investment in the operations of the NOARK Pipeline System, Limited Partnership, corporate assets not allocated to segments, and assets for non-reportable segments.

10

(3)    Exploration and Production capital expenditures include $8.9 million and $10.6 million for the three and six month periods ended June 30, 2005, respectively, and ($5.5) million and $2.6 million for the three and six month periods ended June 30, 2004, respectively, relating to the change in accrued expenditures between periods.

    Included in intersegment revenues of the marketing segment are $59.4 million and $56.2 million for the second quarters of 2005 and 2004, respectively, and $108.7 million and $105.9 million for the six months ended June 30, 2005 and 2004, respectively, for marketing of the Company's exploration and production sales. Intersegment sales by the exploration and production segment and marketing segment to the gas distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include furniture and fixtures, prepaid debt costs and prepaid and intangible pension related costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company's operations are located within the United States.

(7)    INTEREST AND INCOME TAXES PAID

    The following table provides interest and income taxes paid during each period presented:

	For the six months ended
	June 30,
	2005		2004
	(in thousands)
Interest payments	$	10,287	$	8,695
Income tax payments	$	--	$	--

(8)    CONTINGENCIES AND COMMITMENTS

    The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018. At June 30, 2005 and December 31, 2004, the outstanding principal for these notes was $66.0 million and $67.0 million, respectively. The Company's share of the several guarantee is 60%. The notes were issued in June 1998 and require semi-annual principal payments of $1.0 million. Under the several guarantee, the Company is required to fund its share of NOARK's debt service to the extent not funded by operations of the pipeline. Additionally, the Company's gas distribution subsidiary has a transportation contract for firm capacity of 66.9 MMcfd on NOARK's integrated pipeline system under which approximately $2.6 million in costs have been incurred by our gas distribution subsidiary in 2005. This contract expires in 2014.

    The Company leases certain office space and equipment under non-cancelable operating leases expiring through 2013. Under certain of these leases the Company is required to pay property taxes, insurance, repairs and other costs related to the leased property. At June 30, 2005, future minimum payments under non-cancelable leases accounted for as operating leases are approximately $0.9 million in 2005, $1.5 million in 2006, $1.5 million in 2007, $1.5 million in 2008, $1.5 million in 2009 and $2.5 million thereafter. Total rent expense for all operating leases was $0.6 million for the first six months of 2005 and $0.5 million for the comparable period of 2004.

11

    The Company's utility segment has entered into various non-cancelable agreements related to demand charges for the transportation and purchase of natural gas with third parties. These costs are recoverable from the utility's end-use customers. At June 30, 2005, future payments under these non-cancelable demand contracts are $4.3 million in 2005, $8.6 million in 2006, $8.8 million in 2007, $9.2 in 2008, $9.6 million in 2009 and $51.6 million thereafter. Additionally, the E&P segment has a commitment to a third party for demand transportation charges. At June 30, 2005, future payments under these non-cancelable demand contracts are $2.0 million in 2005, $2.7 million in 2006, $0.7 million in 2007, $0.6 million in 2008, $0.6 million in 2009 and $0.4 million thereafter.

    On July 1, 2005, the Company entered into an agreement to fabricate five new land drilling rigs for an aggregate purchase price of $37.7 million. Scheduled payments under this agreement are $27.7 million in 2005 and $10.0 million in 2006.

    The Company is subject to laws and regulations relating to the protection of the environment. The Company's policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company.

    The Company is subject to litigation and claims that arise in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims will not have a material effect on the results of operations or the financial position of the Company.

    A lawsuit was filed against the Company in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to the Company's Boure prospect in Louisiana. The allegations were contested and, in 2002, the Company was granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to the Thirteenth Court of Appeals in Corpus Christi. The appeal was briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying the Company's motion for summary judgment and granting the motion for summary judgment of the other party. The Company's motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. The Company is pursuing this decision to the Texas Supreme Court. Should the other party prevail on the appeal, the Company could be required to pay approximately $2.1 million, plus pre-judgment interest and attorney's fees. Based on an assessment of this litigation by the Company and its legal counsel, no accrual for loss is currently recorded.

(9)    ACCOUNTING FOR STOCK-BASED COMPENSATION

    Stock-based employee compensation issued pursuant to the Company's plans is accounted for under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No stock-based employee compensation cost related to stock options is reflected in net income as all options granted under the plan had an exercise price

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equal to the market value of the underlying common stock on the date of grant. The Company does record compensation cost for the amortization of restricted stock shares issued to employees. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (FAS 123), to stock-based employee compensation.

	For the three months ended				For the six months ended
	June 30,				June 30,
	2005		2004		2005		2004
Net income, as reported	$	26,814	$	20,790	$	59,435	$	45,262
Add back: Amortization of restricted stock		401		304		804		610
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(811)		(595)		(1,624)		(1,192)
Pro forma net income	$	26,404	$	20,499	$	58,615	$	44,680
Earnings per share:
Basic - as reported	$	0.37	$	0.29	$	0.82	$	0.64
Basic - pro forma		0.36		0.29		0.81		0.63
Diluted - as reported		0.36		0.28		0.79		0.62
Diluted - pro forma		0.35		0.28		0.78		0.61

    There were no options granted in the first six months of 2005. There were 7,000 options (pre-split basis) granted in the first six months of 2004 with a fair value of $0.1 million. The fair value of each option grant in 2004 was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: no dividend yield; expected volatility of 47.1%; risk-free interest rate of 3.7%; and expected lives of 6 years.

    As discussed further in Note 12 below, "New Pronouncements," the Company will adopt the provisions of FAS 123 (Revised 2004) in the first quarter of 2006. This standard will require the recognition of the fair value cost of equity awards, including stock options, as an expense over the service period provided by employees and directors.

(10)    PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

    The Company applies Statement of Financial Accounting Standards No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits." Substantially all employees are covered by the Company's defined benefit pension and postretirement benefit plans. Net periodic pension and other postretirement benefit costs include the following components for the three- and six- month periods ended June 30, 2005 and 2004:

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	Pension Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2005	2004	2005	2004
	(in thousands)
Service cost	$ 631	$    601	$  1,262	$  1,202
Interest cost	941	923	1,882	1,846
Expected return on plan assets	(1,194)	(1,136)	(2,388)	(2,272)
Amortization of prior service cost	110	111	220	222
Amortization of net loss	81	58	162	117
Net periodic benefit cost	$ 569	$    557	$  1,138	$  1,115

	Postretirement Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2005	2004	2005	2004
	(in thousands)
Service cost	$   43	$      44	$      86	$      87
Interest cost	50	63	100	126
Expected return on plan assets	(14)	(11)	(28)	(21)
Amortization of net loss	10	29	20	51
Amortization of transition obligation	22	18	44	43
Net periodic benefit cost	$ 111	$    143	$    222	$    286

    The Company currently expects to contribute $1.8 million to its pension plans and $0.4 million to our postretirement benefit plans in 2005. As of June 30, 2005, $1.1 million has been contributed to the pension plans, and $0.2 million has been contributed to the Company's postretirement benefit plans.

(11)    ASSET RETIREMENT OBLIGATIONS

    Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," (FAS 143) was adopted by the Company on January 1, 2003. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells when reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period the liability is incurred (at the time the wells are drilled or acquired). The following table summarizes the Company's activity related

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to asset retirement obligations for the six month period ended June 30, 2005 and for the year ended December 31, 2004:

		2005		2004
		(in thousands)
Asset retirement obligation at January 1	$	8,565	$	7,544
Accretion of discount		161		314
Obligations incurred		409		803
Obligations settled/removed		(1,126) ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9;		(133) &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ;
Revisions of estimates		(183)		37
Asset retirement obligation at June 30, 2005 and December 31, 2004	$	7,826   &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ;	$	8,565   &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ;
Current liability		551   ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9;		473   ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9;
Long-term liability		7,275		8,092
Asset retirement obligation at June 30, 2005 and December 31, 2004	$	7,826	$	8,565   &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ; &# 9; & #9; ;

    For the six months ended June 30, 2005, the obligations settled/removed includes $0.8 million of obligations removed due to the sale of oil and gas properties. The liability for the plugging and abandonment of these properties was assumed by the buyer.

(12)    NEW PRONOUNCEMENTS

    In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (Revised 2004), "Share-Based Payment," revising FASB Statement 123, "Accounting for Stock-Based Compensation" and superseding APB opinion No. 25, "Accounting for Stock Issued to Employees." This statement requires a public entity to measure the cost of services provided by employees and directors received in exchange for an award of equity instruments, including stock options, at a grant-date fair value. The fair value cost is then recognized over the period that services are provided.

    In April 2005, the staff of the Securities and Exchange Commission, or the SEC, issued Staff Accounting Bulletin No. 107 (SAB 107) to provide additional guidance regarding the application of FAS 123 (Revised 2004). SAB 107 permits registrants to choose an appropriate valuation technique or model to estimate the fair value of stock options, assuming consistent application, and provides guidance for the development of assumptions used in the valuation process. Additionally, SAB 107 discusses disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" in registrants' periodic reports.

    Based upon SEC rules issued in April 2005, FAS 123 (Revised 2004) is effective for fiscal years that begin after June 15, 2005 and will be adopted by the Company in the first quarter of 2006. See Note 9 of these financial statements for a disclosure of the effect of net income and earnings per share for the three and six month periods ended June 30, 2005 and 2004 if the Company had applied the fair value recognition provisions of FAS 123 to stock-based employee compensation.

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

    The following updates information as to Southwestern Energy Company's financial condition provided in our 2004 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three- and six-month periods ended June 30, 2005 and the comparable periods of 2004. For definitions of commonly used gas and oil terms used in this Form 10-Q, please refer to the "Glossary of Certain Industry Terms" provided in our 2004 Annual Report on Form 10-K.

    This Form 10-Q contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in "Risk Factors" and elsewhere in our 2004 Annual Report on Form 10-K. You should read the following discussion with our financial statements and related notes included in this Form 10-Q. All historical per share information in the financial statements, footnotes and Management's Discussion and Analysis of Financial Condition and Results of Operations have been adjusted to reflect the two-for-one stock split effected on June 3, 2005.

OVERVIEW

    Southwestern Energy Company is a growing integrated energy company primarily focused on natural gas. Our primary business is the exploration, development and production of natural gas and crude oil, with operations principally located in Arkansas, Oklahoma, Texas, New Mexico and Louisiana. We also operate integrated natural gas distribution systems in northern Arkansas. As a complement to our other businesses, we provide marketing and transportation services in our core areas of operation. All of our operations are located within the United States and we operate principally in three segments: exploration and production (or E&P), natural gas distribution and natural gas marketing.

    Our E&P business has increasingly contributed to our financial results primarily due to the general increase in natural gas and crude oil commodity prices and the growth in our production volumes. For both the three months ended June 30, 2005 and 2004, 100% of our operating income was generated by our E&P and natural gas marketing segments, as our natural gas distribution segment generated a seasonal loss for the second quarter. For the first six months of 2005, 93% of our operating income was generated by our E&P segment, with our natural gas distribution segment generating 5% and our marketing and other businesses generating 2%, as compared to 87%, 9% and 4%, respectively, for the comparable period in 2004. For fiscal year 2004, 90% of our operating income was generated by our E&P segment, with our natural gas distribution generating 5% and our marketing and other businesses also generating 5%.

    We operate our E&P business in four general regions--the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast. Currently our E&P activities in the Arkoma Basin and East Texas generate the majority of our production and proved reserves, accounting for 37% and 41% of production and 38% and 47% of our proved reserves, respectively, in 2004. If we continue to be successful in the development of our Fayetteville Shale play, an unconventional shale gas play on the

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Arkansas side of the Arkoma Basin, we expect the production and proved reserves generated by our activities in the Arkoma Basin to significantly increase over the next several years.

    Our natural gas production has increasingly generated a substantial portion of our total operating revenues as a result of the natural gas focus of our capital investments in the past three years. For the three months ended June 30, 2005, sales of natural gas production accounted for 91% of total operating revenues for the E&P segment as compared with 94% for the comparable period in 2004. For the first six months of 2005 and 2004, sales of natural gas production accounted for 91% of total operating revenues for the E&P segment. For fiscal year 2004, sales of natural gas production accounted for 92% of total operating revenues for the E&P segment as compared with 91% in 2003.

    We currently derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future. We expect that growth in our operating income and revenues will primarily depend on natural gas prices and our ability to increase our natural gas production. There has been significant price volatility in the natural gas and crude oil market in recent years due to a variety of factors we cannot control or predict. These factors, which include weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas. In addition, the price we realize for our gas production is affected by our hedging activities as well as locational differences in market prices. Our ability to increase our natural gas production is dependent upon our ability to economically find and produce natural gas, our ability to control costs, and our ability to market natural gas on economically attractive terms to our customers.

Recent Developments

- Increase in 2005 Capital Expenditures. In July 2005, we announced an increase in our 2005 capital budget to $438.8 million, up from the $352.7 million capital program announced in February of this year, and includes projected capital expenditures of approximately $425.1 million for our E&P segment, up from up to $339.0 million. Of the $86.1 million increase in capital expenditures:

- approximately $27.7 million is related to the 2005 portion of the Company's recent commitment to fabricate five new land drilling rigs, with an additional $6.1 million being allocated for drill pipe and other related equipment;

- approximately $27.0 million is allocated to our Fayetteville Shale play in Arkansas for development drilling and leasehold acquisition costs;

- approximately $15.5 million is being allocated to fund activities in East Texas, which include the drilling of six additional wells at the Overton Field, additional capital for our other East Texas drilling projects and to cover generally higher oil field service costs;

- approximately $5.6 million is allocated to additional drilling and an expansion of the gathering system at the company's Ranger Anticline project area in the Arkoma Basin; and

- approximately $4.2 million is related to our shallow oil drilling program in Eddy County, New Mexico.

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- Purchase of Drilling Rigs. In July 2005, we announced that we had entered into an agreement to fabricate five new land drilling rigs for an aggregate purchase price of $37.7 million. The agreement calls for payments totaling $27.7 million during 2005. We will also incur additional expenditures of approximately $6.1 million in 2005 for drill pipe and other equipment necessary to operate the drilling rigs.

- Two-for One Stock Split. In June 2005, we distributed additional shares of our common stock in a two-for-one stock split that was declared by our board of directors in May 2005.

Three Months Ended June 30, 2005 Compared with Three Months Ended June 30, 2004

    We derive our revenues primarily from our three operating segments. Our revenues for the second quarter of 2005 were approximately 37% higher than the comparable period in 2004 due primarily to higher market-driven commodity prices realized for our gas and oil sales. We reported net income of $26.8 million, or $0.36 per share on a diluted basis, on revenues of $132.5 million for the three months ended June 30, 2005, compared to $20.8 million, or $0.28 per share, on revenues of $96.4 million for the same period in 2004. Operating income for our E&P segment was $48.6 million for the quarter ended June 30, 2005, up from $37.5 million for the same period in 2004. The increases in our net income and in the operating income for the E&P segment were primarily due to a 19% increase in production volumes and higher realized natural gas and oil prices, which were partially offset by an increase in our operating costs and expenses. Our gas distribution segment incurre d a seasonal operating loss of $2.4 million for the three months ended June 30, 2005, compared to a loss of $1.4 million for the same period in 2004. The decrease in operating income for our gas distribution segment resulted primarily from increased operating costs and expenses.

    In the second quarter of 2005, our gas and oil production increased to 15.0 Bcfe, up from 12.6 Bcfe in the second quarter of 2004. The increase in 2005 production primarily resulted from an increase in production from our Overton Field in East Texas, increased production in the Arkoma Basin and increased production from the development of our River Ridge discovery in New Mexico.

    Our capital investments totaled $105.8 million for the second quarter of 2005, up from $68.2 million in the second quarter of 2004. We invested $103.1 million in our E&P segment in the second quarter of 2005, compared to $66.4 million for the same period in 2004.

Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

    Net income for the six months ended June 30, 2005 was $59.4 million, or $0.79 per share on a diluted basis, on revenues of $293.5 million, compared to net income of $45.3 million, or $0.62 per share, on revenues of $216.2 million for the same period in 2004. Operating income for our E&P segment was $96.3 million for the first six months of 2005, up from $70.9 million for the same period in 2004. The increases were due to increased production volumes and higher prices realized for our production. Operating income for our gas distribution segment was $5.1 million for the first six months of 2005, compared to $7.4 million for the same period in 2004. The decrease in operating income for our gas distribution segment resulted primarily from increased operating costs and expenses. Our cash flow from operating activities was $164.4 million for the six months ended June

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30, 2005, compared to $120.5 million for the same period in 2004. The increase in operating cash flow was primarily due to the improved operating results of our E&P segment.

    In the first six months of 2005, our gas and oil production increased to 29.0 Bcfe, up from 24.0 Bcfe in the same period of 2004. The increase in 2005 production primarily resulted from an increase in production from our Overton Field in East Texas, increased production in the Arkoma Basin and increased production from the development of our River Ridge discovery in New Mexico.

    Our capital investments totaled $186.7 million for the first six months of 2005, up from $126.8 million in the first six months of 2004. Our cash flow from operating activities funded 88% of our capital investments in the first six months of 2005, and funded 95% of the capital investments in the first six months of 2004. We invested $181.5 million in our E&P segment in the first six months of 2005, compared to $123.0 million for the same period in 2004. As discussed under "Recent Developments" above, in July 2005, we announced an increase in our 2005 capital budget to $438.8 million, up from the $352.7 million capital program announced in February of this year.

RESULTS OF OPERATIONS

Exploration and Production

	For the three months ended June 30,		For the six months ended June 30,
	2005	2004	2005	2004
Revenues (in thousands)	$87,040	$65,872	$169,583	$124,943
Operating income (in thousands)	$48,599	$37,452	$96,330	$70,881
Gas production (MMcf)	13,940	11,781	26,959	22,296
Oil production (MBbls)	182	140	343	292
Total production (MMcfe)	15,032	12,621	29,019	24,048
Average gas price per Mcf, including hedges	$5.71	$5.25	$5.71	$5.09
Average gas price per Mcf, excluding hedges	$6.46	$5.82	$6.10	$5.59
Average oil price per Bbl, including hedges	$40.81	$28.68	$39.42	$28.55
Average oil price per Bbl, excluding hedges	$50.08	$37.09	$48.88	$35.41
Average unit costs per Mcfe
Lease operating expenses	$0.43	$0.39	$0.44	$0.39
General & administrative expenses	$0.39	$0.35	$0.39	$0.37
Taxes, other than income taxes	$0.32	$0.28	$0.32	$0.27
Full cost pool amortization	$1.38	$1.18	$1.34	$1.18

    Revenues. Revenues for our E&P segment were up 32% to $87.0 million for the three months ended June 30, 2005 and up 36% to $169.6 million for the six months ended June 30, 2005, as compared to the comparable periods in 2004. The increases were primarily due to increased production volumes and higher gas and oil prices realized for our production. Revenues for the first

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six months of 2005 and 2004 also include pre-tax gains of $2.1 million and $3.0 million, respectively, related to the sale of gas in storage inventory.

    Operating Income. Operating income for the E&P segment was up 30% to $48.6million for the second quarter of 2005 and up 36% to $96.3 million for the first six months of 2005, as compared to the respective periods in 2004. The increase in operating income resulted from the increase in revenues, as discussed above, partially offset by increased operating costs and expenses.

    Production. Gas and oil production during the second quarter of 2005 was 15.0 Bcfe, up 19% from 12.6 Bcfe in the second quarter of 2004. Gas and oil production was 29.0 Bcf equivalent for the first six months of 2005, compared to 24.0 Bcf equivalent for the same period of 2004. The comparative increase in production primarily resulted from an increase in production from our Overton Field in East Texas, increased production in the Arkoma Basin and increased production from the development of our River Ridge discovery in New Mexico. Production during the second quarter and first six months of 2005 included the effects of curtailment of a portion of our production at our Overton Field due to pipeline repairs of a non-operated transmission line into which we deliver a large portion of our gas production. Gas production was 13.9 Bcf for the second quarter of 2005 up from 11.8 Bcf for the second quarter of 2004. Gas production was 27.0 Bcf for the first six months of 2 005 compared to 22.3 Bcf for the same period of 2004. Our oil production was 182 MBbls during the second quarter of 2005 and 343 MBbls for the first six months of 2005, up from 140 MBbls and 292 MBbls for the same periods of 2004, respectively.

    Average Realized Prices. The average price realized for our gas production, including the effect of hedges, was $5.71 per Mcf for the three months ended June 30, 2005, up from $5.25 per Mcf for the same period of 2004. For the first six months of 2005, we received an average gas price of $5.71 compared to $5.09 for the same period of 2004. The change in the average prices realized primarily reflects changes in average spot market prices and the effects of our price hedging activities. Our hedging activities decreased the average gas price realized during the second quarter of 2005 by $0.75 per Mcf compared to $0.57 per Mcf for the same period of 2004. Our hedging activities decreased the average gas price realized by $0.39 per Mcf for the first six months of 2005, compared to a decrease of $0.50 per Mcf during the same period of 2004. Locational differences in market prices for natural gas have continued to be wider than historically experienced. Disregarding the impact of hedges, the average price received for our gas production during the second quarter of 2005 was approximately $0.27 lower than average NYMEX spot prices, compared to the average for the prior year period of approximately $0.17 per Mcf. The average price received for our gas production during the first half of 2005 was approximately $0.40 lower than average NYMEX spot prices, compared to the average for the prior year period of approximately $0.25 per Mcf.

    We realized an average price of $39.42 per barrel for our oil production, including the effect of hedges, during the six months ended June 30, 2005, up from $28.55 per barrel for the same period of 2004. The average price we received for our oil production in the first six months of 2005 and 2004 was reduced by $9.46 per barrel and $6.86 per barrel, respectively, due to the effects of our hedging activities.

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    Hedging Activities. We periodically enter into hedging activities with respect to a portion of our projected natural gas and crude oil production through a variety of financial arrangements intended to support natural gas and oil prices at targeted levels and to minimize the impact of price fluctuations. Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.For the remainder of 2005, we have hedges in place for 21.9 Bcf of gas production and for 2006 and 2007 we have 45.1 Bcf and 26.0 Bcf, respectively, of our future gas production hedged. For the remainder of 2005, we have hedged 180 MBbls of our oil production at an average NYMEX price of $33.17 per barrel. For 2006 we have hedged 120 MBbls of our future oil production. For additional information regarding our commodity price risk hedging activities, we refer you to Part I, Item 3 of this Form 10-Q.

    Lease Operating Expenses. Lease operating expenses per Mcfe for our E&P segment were $0.43 and $0.44 for the second quarter and first six months of 2005, respectively, compared to $0.39 for both the second quarter and first six months of 2004. The increases in lease operating expenses per Mcfe for the second quarter and first six months of 2005, as compared to the prior year, resulted from an increase in compression costs and generally higher oil field service costs.

    General & Administrative Expenses. General and administrative expenses per Mcfe were $0.39 for the second quarter of 2005 and $0.39 for the six months ended June 30, 2005, compared to $0.35 and $0.37 for the same periods of 2004. General and administrative expenses for our E&P segment increased to $11.3 million for the first six months of 2005, compared to $8.9 million for the same period of 2004 due primarily to increased compensation costs associated with increased staffing levels.

    Taxes Other Than Income Taxes. Taxes other than income taxes per Mcfe were $0.32 for both the second quarter and the first six months of 2005, compared to $0.28 and $0.27 for the comparable periods in 2004. The increase in severance taxes per Mcfe in 2005 is primarily due to comparatively higher average market prices in effect for natural gas and crude oil, as reflected in the average price received for our production excluding the effect of hedges.

    Full Cost Pool Amortization. Our full cost pool amortization rate was $1.38 per Mcfe for the second quarter of 2005 and $1.34 for the first six months of 2005, compared to $1.18 per Mcfe for the same periods in 2004. The increase in our full cost pool amortization rate was primarily due to increased finding and development costs. We currently expect our full cost pool amortization rate to average between $1.40 and $1.45 per Mcfe for 2005. Depreciation, depletion and amortization expense for our E&P segment increased to $39.8 million for the first six months of 2005, compared to $29.3 million for the same period of 2004 as a result of the 19% increase in our production volumes and the increase in the per unit rate of amortization.

    Full Cost Pool Ceiling. We utilize the full cost method of accounting for capitalizing costs related to our natural gas and oil properties. As discussed in Note 2 to the financial statements, these capitalized costs are subject to a ceiling test that limits our pooled costs and requires us to write-off costs in excess of the ceiling as a non-cash expense. At June 30, 2005, our unamortized costs of gas and oil properties did not exceed the ceiling amount. Our standardized measure at June 30, 2005 was calculated based upon quoted market prices of $7.02 per Mcf for Henry Hub gas and $56.50 per barrel for West Texas Intermediate oil, adjusted for market differentials. A decline in natural gas and oil prices from June 30, 2005 levels or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

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Natural Gas Distribution

	For the three months ended June 30,		For the six months ended June 30,
	2005	2004	2005	2004
Revenues (in thousands)	$24,433	$23,012	$87,184	$84,271
Gas purchases (in thousands)	$14,237	$12,994	$56,732	$54,342
Operating costs and expenses (in thousands)	$12,557	$11,446	$25,366	$22,547
Operating income (loss) (in thousands)	($2,361)	($1,428)	$5,086	$7,382
Deliveries to sales and end-use transportation customers (Bcf)	3.8	3.9	13.0	13.7
Customers at period-end	143,855	140,227	143,855	140,227
Average sales rate per Mcf	$12.57	$11.06	$9.89	$8.73
Heating weather - degree days	315	261	2,217	2,322
Percent of normal	98%	84%	90%	95%

    Revenues. Gas distribution revenues fluctuate due to the pass-through of gas supply cost changes and the effects of weather. Because of the corresponding changes in purchased gas costs, the revenue effect of the pass-through of gas cost changes has not materially affected net income. Revenues for the three- and six-month periods ended June 30, 2005 increased 6% and 3%, respectively, from the comparable periods of 2004 due to higher gas prices, partially offset by lower volumes delivered to customers.

    Operating Income. Operating income for our gas distribution segment decreased by approximately $0.9 million in the second quarter of 2005 and by approximately $2.3 million for the first six months of 2005, compared to comparable periods of 2004, due to decreased deliveries caused by warmer weather and increased operating costs and expenses. Weather during the first six months of 2005 was 10% warmer than normal and 5% warmer than the same period in 2004.

    Deliveries. The utility systems delivered 3.8 Bcf and 13.0 Bcf to sales and end-use transportation customers during the three- and six-month periods ended June 30, 2005, compared to 3.9 Bcf and 13.7 Bcf for the same periods in 2004. The decrease in deliveries during the first half of 2005 was primarily due to the effects of warmer weather and continued customer conservation brought about by high gas prices.

    Rates. Our utility's tariffs contain a weather normalization clause intended to lessen the impacts of revenue increases and decreases that might result from weather variations during the winter heating season. The increase in gas costs in the first six months of 2005 was reflected in the utility segment's average rate for its sales which increased to $9.89 per Mcf, up from $8.73 per Mcf for the same period in 2004. The fluctuations in the average sales rate primarily reflect changes in the average cost of gas purchased for delivery to our customers, which are passed through to customers under automatic adjustment clauses.

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    Hedging Activities. Our utility segment hedged 2.9 Bcf of gas purchases in the first half of 2005 which had the effect of increasing its total gas supply cost by $1.4 million. In the first six months of 2004, our utility hedged 3.8 Bcf of its gas supply which decreased its total gas supply cost by $0.1 million. For additional information regarding our commodity price risk hedging activities, we refer you to Part I, Item 3 of this Form 10-Q.

    Operating Costs and Expenses. The changes in purchased gas costs for our gas distribution segment reflect volumes purchased, prices paid for supplies and the mix of purchases from various gas supply contracts (base load, swing and no-notice). Other operating costs and expenses for this segment during both the second quarter and the first half of 2005 were higher than the comparable period of the prior year due primarily to higher general and administrative expenses. The increase in general and administrative expense primarily resulted from increased compensation costs.

Marketing

	For the three months ended June 30,		For the six months ended June 30,
	2005	2004	2005	2004
Revenues (in thousands)	$92,302	$72,435	$171,367	$133,695
Operating income (in thousands)	$931	$811	$1,968	$1,698
Gas volumes marketed (Bcf)	15.0	13.1	29.4	25.4

    Revenues. Revenues from natural gas marketing were $92.3 million and $171.4 million for the three- and six-month periods ended June 30, 2005, compared to $72.4 million and $133.7 million for the comparable periods of 2004. The increase in revenues from natural gas marketing is attributable to increased volumes marketed and an increase in natural gas commodity prices. The increase in revenues was largely offset by a comparable increase in purchased gas costs.

    Operating Income. Our operating income from natural gas marketing was $0.9 million for the second quarter of 2005 and $2.0 million for the first six months of 2005, compared to $0.8 million and $1.7 million for the comparable periods of 2004. Operating income from natural gas marketing fluctuates depending on the margin we are able to generate between the purchase of the commodity and the ultimate disposition of the commodity.

    Gas Volumes Marketed. We marketed 11.0 Bcf of affiliated gas in the second quarter of 2005, representing 73% of total volumes marketed, compared to 10.1 Bcf, or 77% of total volumes marketed, for the same period in 2004. Affiliated gas marketed for the first six months of 2005 was 21.7 Bcf compared to 20.2 Bcf for the same period in 2004. We enter into hedging activities from time to time with respect to our gas marketing activities to provide margin protection. We refer you to Item 3, "Qualitative and Quantitative Disclosure about Market Risks" in this Form 10-Q for additional information.

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Transportation

    We recorded pre-tax income from operations related to our investment in the NOARK Pipeline System Limited Partnership (NOARK) of $0.2 million for the second quarter of 2005 and $0.3 million for the first six months of 2005, compared to pre-tax losses of $0.7 million and $0.5 million for the comparable periods of 2004. These amounts were recorded in other income (expense) in our statements of operations.

Interest Expense

    Interest costs, net of capitalization, increased 18% for the second quarter of 2005 and 10% for the first six months of 2005, as compared to the same periods of 2004. The increase in interest costs in 2005 resulted from higher average borrowings during the period at higher interest rates. Changes in capitalized interest are primarily due to the level of costs excluded from amortization in our E&P segment.

Income Taxes

    Our effective tax rate was approximately 37% for the three- and six-month periods ended June 30, 2005 and 2004. The changes in the provision for deferred income taxes recorded each period result primarily from the level of income before income taxes, adjusted for permanent differences.

Pension Expense

    We recorded pension expense of $0.6 million in the second quarters of both 2005 and 2004, and $1.1 million for the first six months of both 2005 and 2004. The amount of pension expense recorded by us is determined by actuarial calculations and is also impacted by the funded status of our plans. We currently expect to contribute $1.8 million to our pension plans in 2005. As of June 30, 2005, we have contributed $1.1 million to our pension plans. For further information regarding our pension plans, we refer you to Note 10 of the financial statements in this Form 10-Q.

New Accounting Principles

    In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (Revised 2004), "Share-Based Payment," revising FASB Statement 123, "Accounting for Stock-Based Compensation" and superseding APB opinion No. 25, "Accounting for Stock Issued to Employees." This statement requires a public entity to measure the cost of services provided by employees and directors received in exchange for an award of equity instruments, including stock options, at a grant-date fair value. The fair value cost is then recognized over the period that services are provided.

In April 2005, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 (SAB 107) to provide additional guidance regarding the application of FAS 123 (Revised 2004). SAB 107 permits registrants to choose an appropriate valuation technique or model to estimate the fair value of share options, assuming consistent application, and provides guidance for the development of assumptions used in the valuation process. Additionally, SAB 107 discusses

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disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" in registrants' periodic reports.

    Based upon SEC rules issued in April 2005, FAS 123 (Revised 2004) is effective for fiscal years that begin after June 15, 2005 and will be adopted by us in the first quarter of 2006. In Note 9 of the financial statements included in this Form 10-Q, we disclose the effect on net income and earnings per share for the three- and six-month periods ended June 30, 2005 and 2004 if we had applied the fair value recognition provisions of FAS 123 to stock-based employee compensation.

LIQUIDITY AND CAPITAL RESOURCES

    We depend on internally-generated funds and our unsecured revolving credit facility (discussed below under "Financing Requirements") as our primary sources of liquidity. We have the ability to borrow up to $500 million under our revolving credit facility from time to time. As of June 30, 2005, we had $103.1 million of indebtedness outstanding under our revolving credit facility. During 2005, we expect to draw on a portion of the funds available under our credit facility to fund at least a portion of our planned capital expenditures (discussed below under "Capital Expenditures"), which are expected to exceed the net cash generated by our operations. We may also seek to access the equity and debt markets to enhance our liquidity.

    Net cash provided by operating activities was $164.4 million in the first six months of 2005, compared to $120.5 million for the same period of 2004. Net cash provided by operating activities primarily consists of net income adjusted for depreciation, depletion and amortization, the provision for deferred income taxes and changes in operating assets and liabilities. For the first six months of 2005 and 2004, cash provided by operating activities provided 88% and 95%, respectively, of our requirements for capital expenditures.

    Our cash flow from operating activities is highly dependent upon the market prices that we receive for our gas production. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Note 5 to the financial statements included in this Form 10-Q and Item 3, "Quantitative and Qualitative Disclosures about Market Risks." Natural gas and oil prices are subject to wide fluctuations. As a result, we are unable to forecast with certainty our future level of cash flow from operations. We adjust our discretionary uses of cash dependent upon cash flow available.

Capital Expenditures

    Our capital expenditures for the first six months of 2005 were $186.7 million, including $10.6 million relating to the effects of accrued expenditures, compared to $126.8 million for the same period in 2004 including $2.6 million relating to the change in the amount of accrued expenditures. In July 2005, we announced an increase in our 2005 capital budget to $438.8 million, up from the $352.7 million capital program announced in February of this year, which includes projected capital expenditures of approximately $425.1 million for our E&P segment, up from up to $339.0 million. Of the $86.1 million increase in capital expenditures, approximately $27.7 million is related to the 2005 portion of the Company's recent commitment to fabricate five new land drilling rigs, with an additional $6.1 million being allocated for drill pipe and other related equipment; approximately $27.0

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million is allocated to our Fayetteville Shale play in Arkansas for development drilling and leasehold acquisition costs; approximately $15.5 million is being allocated to fund activities in East Texas, which include the drilling of six additional wells at the Overton Field, additional capital for our other East Texas drilling projects and to cover generally higher oil field service costs; approximately $5.6 million is allocated to additional drilling and an expansion of the gathering system at the company's Ranger Anticline project area in the Arkoma Basin; and approximately $4.2 million is related to our shallow oil drilling program at our No Bluff prospect in Eddy County, New Mexico. Our 2005 capital investment program is expected to be funded through cash flow from operations, borrowings under our revolving credit facility and/or proceeds from any equity or debt offering we might pursue. We may adjust our level of 2005 capital investments dependent upon the level of cash flow generated from operations, ability to borrow under our credit facility, and our access to th e capital markets.

Financing Requirements

    Our total debt outstanding was $328.1 million at June 30, 2005 and $325.0 million at December 31, 2004. The total debt at June 30, 2005 included $125 million of 6.70% senior notes due December 2005, which we intend to use our credit facility to repay. Of the total outstanding at June 30, 2005, $103.1 million was outstanding under our revolving credit facility. In January 2005, we amended and restated our previous $300 million revolving credit facility due to expire in January 2007, increasing the borrowing capacity to $500 million and extending the expiration to January 2010. The amended and restated credit facility also replaced another smaller credit facility. The interest rate on the new facility is calculated based upon our debt rating and is currently 125 basis points over the current London Interbank Offered Rate (LIBOR). Our publicly traded notes are rated Ba2 by Moody's and BBB- by Standard & Poor's, following a downgrade from BBB in January 2005. Any future downgrades in our public debt ratings could increase the cost of funds under our revolving credit facility.

    Our revolving credit facility contains covenants which impose certain restrictions on us. Under the credit agreements, we may not issue total debt in excess of 60% of our total capital, must maintain a certain level of shareholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. EBITDA is a measure required by our debt covenants and is defined as net income plus interest expense, income tax expense, and depreciation, depletion and amortization. Additionally, there are also restrictions on the ability of our subsidiaries to incur debt. We were in compliance with the covenants of our debt agreements at June 30, 2005. Although we do not anticipate any debt covenant violations, our ability to comply with our credit agreement is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil. If we are unable to borrow under our credit facility, we would have to decrease our capital expenditure plans.

    At June 30, 2005, our capital structure consisted of 40% debt (excluding our several guarantee of NOARK's obligations) and 60% equity, with a ratio of EBITDA to interest expense of 16.3. Shareholders' equity in the June 30, 2005 balance sheet includes an accumulated other comprehensive loss of $49.3 million related to our hedging activities that is required to be recorded under the

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provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). This amount is based on the market value of our hedges as of June 30, 2005, and does not necessarily reflect the value that we will receive or pay when the hedges ultimately are settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged. Our debt covenants as to capitalization percentages exclude the effects of non-cash entries that result from FAS 133 as well as the non-cash impact of any full cost ceiling write-downs, and include the guarantee of NOARK's obligations. Our capital structure, including $39.6 million relating to our several guarantee of NOARK's obligations, would be 41% debt and 59% equity at June 30, 2005, without consideration of the accumulated other comprehensive loss related to FAS 133 of $49.3 million.

    As part of our strategy to insure a certain level of cash flow to fund our operations, we have hedged approximately 70% to 80% of our expected 2005 gas production and 60% to 70% of our expected 2005 oil production. The amount of long-term debt we incur will be dependent upon commodity prices and our capital expenditure plans. If commodity prices remain at or near current levels throughout 2005 and our projected capital expenditures do not change, we may issue equity or incur long-term debt during the remainder of 2005. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital expenditures significantly.

Off-Balance Sheet Arrangements

    We hold a 25% general partnership interest in NOARK, which owns the Ozark Pipeline that is utilized to transport our gas production and the gas production of others. We account for our investment under the equity method of accounting. We and the other general partner of NOARK have severally guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018. The notes were issued in June 1998 to partially finance the original construction cost of the NOARK Pipeline. Our share of the guarantee is 60% and we are allocated 60% of the interest expense. At June 30, 2005, the outstanding principal amount of these notes was $66.0 million and our share of the guarantee was $39.6 million. The notes require semi-annual principal payments of $1.0 million. Under the several guarantee, we are required to fund our share of NOARK's debt service which is not funded by operations of the pipeline. We were not required to advance any funds to NOARK in the first half of 2005 and 2004. We do not derive any liquidity, capital resources, market risk support or credit risk support from our investment in NOARK.

    Our share of the results of operations included in other income (expense) related to our NOARK investment was pre-tax income of $0.2 million for the second quarter of 2005 and $0.3 million for the first six months of 2005, compared to pre-tax losses of $0.7 million and $0.5 million for the comparable periods of 2004.

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Contractual Obligations and Contingent Liabilities and Commitments

    We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations at June 30, 2005 were as follows:

Contractual Obligations

	Payments Due by Period
	Total		Less than 1 Year		1 to 3 Years		3 to 5 Years		More than 5 Years
	(in thousands)
Long-term debt	$	328,100	$	125,000	$	-	$	163,100	$	40,000
Interest on senior notes (1)		56,400		10,972		14,918		9,593		20,917
Operating leases(2)		9,420		1,638		3,071		2,991		1,720
Unconditional purchase obligations(3)		-		-		-		-		-
Demand charges(4)		98,657		11,994		19,463		20,409		46,791
Other obligations(5)		4,313		4,263		50		-		-
	$	496,890	$	153,867	$	37,502	$	196,093	$	109,428

(1) Interest on senior notes includes interest on the $60 million notes that are due in 2009. These notes are due in 2027 and putable at the holder's option in 2009. Interest on the revolver will vary with the revolver balance and the variable rate and is not included in the above table. At 6/30/05, the revolver balance was $103.1 million and the variable interest rate was 4.49%.

(2) We lease certain office space and equipment under non-cancelable operating leases expiring through 2013.

(3) Our utility segment has volumetric commitments for the purchase of gas under non-cancelable competitive bid packages and non-cancelable wellhead contracts. Volumetric purchase commitments at June 30, 2005 totaled 1.4 Bcf, comprised of 0.9 Bcf in less than one year, 0.3 Bcf in one to three years, and 0.2 Bcf in three to five years. Our volumetric purchase commitments are priced primarily at regional gas indices set at the first of each future month. These costs are recoverable from the utility's end-use customers.

(4) Our utility segment has commitments for approximately $92.1 million of demand charges on non-cancelable firm gas purchase and firm transportation agreements. These costs are recoverable from the utility's end-use customers. Our E&P segment has a commitment for approximately $6.5 million of demand transportation charges.

(5) Our significant other contractual obligations include approximately $1.7 million for funding of benefit plans, approximately $1.0 million of various information technology support and data subscription agreements, approximately $1.0 million for drilling rig commitments, and approximately $0.3 million of land leases.

    We refer you to Note 4 of the financial statements for a discussion of the terms of our long-term debt.

    In July 2005, we announced that we had entered into an agreement to fabricate five new land drilling rigs for an aggregate purchase price of $37.7 million. The agreement calls for payments totaling $27.7 million during 2005, with the remainder due in early 2006.

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Contingent Liabilities or Commitments

    Substantially all of our employees are covered by defined benefit and postretirement benefit plans. As a result of actuarial data, we expect to record pension expense of approximately $2.3 million in 2005, $1.1 million of which has been recorded in the first six months of 2005. For further information regarding our pension plans, we refer you to Note 10 of the financial statements in this Form 10-Q. In addition, as discussed above in "Off-Balance Sheet Arrangements," we have guaranteed 60% of the principal and interest payments on NOARK's 7.15% Notes due 2018. At June 30, 2005 the outstanding principal of these notes was $66.0 million and our share of the guarantee was $39.6 million. The notes require semi-annual principal payments of $1.0 million. The foregoing obligations represent commitments and contingencies that could create, increase or accelerate our liabilities.

    We are subject to litigation and claims that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable. A lawsuit was filed against us in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to our Boure prospect in Louisiana. The allegations were contested and, in 2002, we were granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to th e Thirteenth Court of Appeals in Corpus Christi. The appeal was briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying our motion for summary judgment and granting the motion for summary judgment of the other party. Our motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. We are pursuing this decision to the Texas Supreme Court. Should the other party prevail on the appeal, we could be required to pay approximately $2.1 million, plus pre-judgment interest and attorney's fees.

Working Capital

    We maintain access to funds that may be needed to meet capital requirements through our above-described credit facility. We had negative working capital of $54.1 million at June 30, 2005, compared to negative working capital of $2.7 million at December 31, 2004. At June 30, 2005, we had $396.9 million of available borrowing capacity under our revolving credit facility. Our current assets decreased by 16% in the first six months of 2005 while current liabilities increased 22% compared to December 31, 2004. The change in working capital from December 31, 2004 to June 30, 2005 primarily relates to the increase in our current hedging liability and the seasonal decrease in our gas distribution accounts receivable.

Gas in Underground Storage

    We record our gas stored in inventory owned by the E&P segment at the lower of weighted average cost or market. Gas expected to be cycled within the next 12 months is recorded in current

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assets with the remaining stored gas reflected as a long-term asset. The quantity and average cost of gas in storage was 7.6 Bcf at $3.15 at June 30, 2005 and 9.3 Bcf at $3.49 at December 31, 2004.

    The gas in inventory for the E&P segment is used primarily to supplement field production in meeting the segment's contractual commitments including delivery to customers of our gas distribution business, especially during periods of colder weather. As a result, demand fees paid by the gas distribution segment to the E&P segment, which are passed through to the utility's customers, are a part of the realized price of the gas in storage. In determining the lower of cost or market for storage gas, we utilize the gas futures market in assessing the price we expect to be able to realize for our gas in inventory. A significant decline in the future market price of natural gas could result in a write down of our gas in storage carrying cost.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

    All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements.

    Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as "anticipate," "project," "intend," "estimate," "expect," "believe," "predict," "budget," "projection," "goal," "plan," "forecast," "target" or similar expressions.

    You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

* the timing and extent of changes in commodity prices for natural gas and oil;

* the timing and extent of our success in discovering, developing, producing and estimating reserves;

* the extent to which the Fayetteville Shale play can replicate the results of other productive shale gas plays;

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* the potential for significant variability in reservoir characteristics of the Fayetteville Shale over such a large acreage position;

* the extent of our success in drilling and completing horizontal wells;

* our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation;

* our ownership and operation of drilling rigs, including our lack of prior experience;

* our ability to fund our planned capital expenditures;

* our future property acquisition or divestiture activities;

* the effects of weather and regulation on our gas distribution segment;

* increased competition;

* the impact of federal, state and local government regulation;

* the financial impact of accounting regulations and critical accounting policies;

* changing market conditions and prices (including regional basis differentials);

* the comparative cost of alternative fuels;

* conditions in capital markets and changes in interest rates;

* the availability of oil field personnel, services, drilling rigs and other equipment; and

* any other factors listed in the reports we have filed and may file with the SEC.

    We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in our 2004 Annual Report on Form 10-K and this Form 10-Q.

    Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of natural gas and oil that are ultimately recovered.

    Should one or more of the risks or uncertainties described above or elsewhere in our 2004 Annual Report on Form 10-K or this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking

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statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

    Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of customers and their dispersion across geographic areas. No single customer accounted for greater than 6% of accounts receivable at June 30, 2005. See the discussion of credit risk associated with commodities trading below.

Interest Rate Risk

    Revolving debt obligations are sensitive to changes in interest rates. Our policy is to manage interest rates through use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposures when appropriate, although we do not have any interest rate swaps in effect currently.

Commodities Risk

    We use over-the-counter natural gas and crude oil swap agreements and options to hedge sales of our production, to hedge activity in our marketing segment, and to hedge the purchase of gas in our utility segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the New York Mercantile Exchange (NYMEX) futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the contracted floor, and a "ceiling" price above which we pay to (production hedge) or receive from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling.

    The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The

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counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are periodically reviewed to ensure limited credit risk exposure.

    The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for our gas and oil production, gas purchases and marketing activities. The table presents the notional amount in Bcf and MBbls, the weighted average contract prices, and the fair value by expected maturity dates. At June 30, 2005, the fair value of these financial instruments was an $80.8million liability.

	Expected Maturity Date
	2005	2006	2007
Production and Marketing
Natural Gas
Swaps with a fixed price receipt
Contract volume (Bcf)	7.9	7.1	12.0
Weighted average price per Mcf	$5.00	$6.29	$6.66
Fair value (in millions)	($18.6)	($11.0)	($10.6)
Price collars
Contract volume (Bcf)	14.0	38.0	14.0
Weighted average floor price per Mcf	$4.64	$5.18	$6.00
Fair value of floor (in millions)	-	$1.5	$0.9
Weighted average ceiling price per Mcf	$7.30	$9.67	$10.68
Fair value of ceiling (in millions)	($11.1)	($21.5)	($3.4)
Swaps with a fixed price payment
Contract volume (Bcf)	0.1	-	-
Weighted average price per Mcf	$6.17	-	-
Fair value (in millions)	$0.1	-	-
Oil
Swaps with a fixed price receipt
Contract volume (MBbls)	180	120	-
Weighted average price per Bbl	$33.17	$37.30	-
Fair value (in millions)	($4.5)	($2.6)	-

    At June 30, 2005, we had outstanding fixed-price basis differential swaps on 6.3 Bcf of 2005 and 8.2 Bcf of 2006 gas production that did not qualify for hedge accounting treatment. The fair value of these differential swaps was a liability of $0.2 million at June 30, 2005. We entered into additional fixed-price basis differential swaps relating to approximately 2.0 Bcf and 4.0 Bcf of 2005 and 2007 gas production, respectively, subsequent to the end of the quarter. We also entered into a natural gas price collar relating to approximately 4.0 Bcf of 2007 gas production subsequent to the end of the quarter.

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    At December 31, 2004, we had outstanding natural gas price swaps on total notional volumes of 12.9 Bcf at a weighted average price per Mcf of $5.11 in 2005 and 5.0 Bcf at a weighted average price per Mcf of $5.89 in 2006. Outstanding oil price swaps on 360 MBbls are yielding us an average price of $33.17 per barrel during 2005. At December 31, 2004, we also had outstanding natural gas price swaps on total notional gas purchase volumes of 2.9 Bcf in 2005 for which we paid an average fixed price of $6.54 per Mcf.

    At December 31, 2004, we had collars in place on 33.4 Bcf in 2005 and 22.0 Bcf in 2006 of gas production. The collars relating to 2005 production have a weighted average floor and ceiling price of $4.68 and $8.30 per Mcf, respectively. The collars relating to 2006 production have a weighted average floor and ceiling price of $4.64 and $8.69 per Mcf, respectively.

ITEM 4.  CONTROLS AND PROCEDURES

    We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, summarize and report the information that is required to be disclosed or submitted by us within the time periods specified in the SEC's rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer , concluded that our disclosure controls and procedures were effective as of June 30, 2005. There were no significant changes in our internal control over financial reporting during the three months ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.  During the second quarter of 2005, we converted the accounting software systems used for our primary accounting processes and for financial reporting to a new version of software. The software conversion process did not materially affect our internal controls over financial reporting.

35

PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

    The Company is subject to litigation and claims that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on the Company's financial position or its results of operations but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company's financial position and the results of operations for the period in which the effect becomes reasonably estimable. A lawsuit was filed against the Company in 2001 alleging a breach of an agreement to indemnify the other party against settlement payments related to the Company's Boure prospect in Louisiana. The allegations were contested and, in 2002, the Company was granted a motion for summary judgment by the trial court. The case was appealed to the First Court of Appeals in Houston, Texas, which subsequently transferred the appeal to the Thirteenth Court of Appeals in Corpus Christi. The appeal was briefed and argued during 2003. On April 14, 2005, the Thirteenth Court of Appeals reversed the orders of the trial court and rendered judgment denying the Company's motion for summary judgment and granting the motion for summary judgment of the other party. The Company's motion for rehearing with the Thirteenth Court of Appeals was denied on May 19, 2005. The Company is pursuing this decision to the Texas Supreme Court. Should the other party prevail on the appeal, the Company could be required to pay approximately $2.1 million, plus pre-judgment interest and attorney's fees.

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

    The Company recently determined that shares of Company common stock purchased under the Company's 401(k) Savings Plan (the "Plan") were not registered with the Securities and Exchange Commission ("SEC") as required. On June 8, 2005, the Company filed a registration statement on Form S-8 to register Company common stock offered under the Plan. On June 16, 2005, the Company filed a registration statement on Form S-3 with the SEC pursuant to which the Company is offering to rescind (the "Rescission Offer") the previous purchase of a total of 49,721 shares of Company common stock by the Plan trustee relating to elections made by participants to invest in the Company stock fund during the period of June 8, 2004 to June 8, 2005. The Registration Statement on Form S-3 was subsequently declared effective on July 8, 2005 and the Rescission Offer commenced on that date. The Rescission Offer is scheduled to expire on August 8, 2005.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

36

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

    The Company held its Annual Meeting of Shareholders on May 11, 2005, for the purpose of electing Directors of the Company for the ensuing year, to ratify the appointment of PricewaterhouseCoopers LLP to serve as the Company's independent registered public accounting firm for 2005, to vote on a proposal to amend the Company's Restated Articles of Incorporation to increase the number of authorized shares of common stock to 220,000,000 shares, and to vote on a proposal to increase the Company's bonded indebtedness by an additional $200 million. The voting was held prior to the stock split distributed in June 2005, therefore the shares reported as voted in this Item 4 are on a pre-split basis. Holders of 32,529,429 shares (89.2% of total outstanding shares) voted in total.

    Holders of 31,107,555 shares voted for the election of directors and holders of 1,421,874 shares withheld their votes. The Directors were elected with the number of shares voted as follows:

	Voted For	Withheld
Lewis E. Epley, Jr.	31,754,874	584,247
John Paul Hammerschmidt	31,240,520	1,094,429
Robert L. Howard	31,758,318	580,803
Harold M. Korell	32,504,077	1,171,372
Vello A. Kuuskraa	30,980,455	1,358,666
Kenneth R. Mourton	31,758,234	580,887
Charles E. Scharlau	30,917,247	1,421,874

    Holders of 32,026,486 shares voted for the proposal to ratify the appointment of PricewaterhouseCoopers LLP to serve as the Company's independent registered public accounting firm for 2005, 481,765 shares voted against, and 21,178 shares abstained.

    Holders of 30,675,305 shares voted for the proposal to amend the Company's Restated Articles of Incorporation to increase the number of authorized shares of common stock to 220,000,000 shares, 1,822,232 shares voted against, and 31,891 shares abstained.

    Holders of 26,428,490 shares voted for the proposal to increase the Company's bonded indebtedness by an additional $200 million, 486,912 shares voted against, and 5,614,027 shares were non-voted or abstained.

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS

(3.1) Second Amended and Restated Articles of Incorporation of the Registrant. (Filed as Exhibit 4.1 to the Registrant's Registration Statement on Form S-3 (No. 333-125859), filed June 16, 2005, and incorporated herein by reference).

37

(31.1) Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2) Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

38

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.

		SOUTHWESTERN ENERGY COMPANY
		Registrant
Dated:	July 26, 2005	/s/ GREG D. KERLEY
		Greg D. Kerley
		Executive Vice President
		and Chief Financial Officer

39

EX-31

Exhibit 31.1

CERTIFICATION

I, Harold M. Korell, Chief Executive Officer of Southwestern Energy Company, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy 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 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.) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c.) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d.) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's control over financial reporting; and
	5. The registrant's other certifying officer 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 registrant's board of directors (or persons performing the equivalent function):
		(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:	July 26, 2005	/s/ HAROLD M. KORELL
			Harold M. Korell
			Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, Greg D. Kerley, Chief Financial Officer of Southwestern Energy Company, certify that:
	1. I have reviewed this quarterly report on Form 10-Q of Southwestern Energy 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 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.) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c.)  evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d.) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's control over financial reporting; and
	5. The registrant's other certifying officer 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 registrant's board of directors (or persons performing the equivalent function):
		(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:	July 26, 2005	/s/ GREG D. KERLEY
			Greg D. Kerley
			Chief Financial Officer

EX-32

Exhibit 32.1

CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Southwestern Energy Company, an Arkansas corporation (the "Company"), does hereby certify that:
	The Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (the "Form 10-Q") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:	July 26, 2005	/s/ HAROLD M. KORELL
			Harold M. Korell
			Chief Executive Officer
Dated:	July 26, 2005	/s/ GREG D. KERLEY
			Greg D. Kerley
			Chief Financial Officer