SOUTHWESTERN ENERGY CO - 10-Q Quarterly Report

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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, 2004

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 1-8246

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 27, 2004
Common Stock, Par Value $0.10		36,167,339

PART I

FINANCIAL INFORMATION


SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		For the three months ended				For the six months ended
		June 30,				June 30,
		2004		2003		2004		2003
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	73,838	$	49,286	$	174,857	$	126,993
	Gas marketing		15,674		11,667		24,860		24,273
	Oil sales		4,008		3,821		8,342		7,280
	Gas transportation and other		2,907		1,713		8,158		6,596
			96,427		66,487		216,217		165,142
Operating Costs and Expenses:
	Gas purchases - utility		3,518		2,199		35,050		29,247
	Gas purchases - marketing		14,572		10,850		22,635		22,408
	Operating expenses		10,498		9,248		20,210		18,294
	General and administrative expenses		8,264		7,663		16,274		15,546
	Depreciation, depletion and amortization		17,091		13,686		32,617		26,069
	Taxes, other than income taxes		4,238		2,895		7,878		5,958
			58,181		46,541		134,664		117,522
Operating Income			38,246		19,946		81,553		47,620

Interest Expense:
	Interest on long-term debt		4,376		4,075		8,797		9,002
	Other interest charges		316		337		828		722
	Interest capitalized		(745)		(501)		(1,293)		(866)
			3,947		3,911		8,332		8,858
Other Income (Expense)			(868)		(63)		(547)		1,359

Income Before Income Taxes, Minority Interest & Accounting Change			33,431		15,972		72,674		40,121
Minority Interest in Partnership			(431)		(609)		(830)		(1,374)

Income Before Income Taxes & Accounting Change			33,000		15,363		71,844		38,747
Provision for Income Taxes - Deferred			12,210		5,837		26,582		14,724

Income Before Accounting Change			20,790		9,526		45,262		24,023
Cumulative Effect of Adoption of Accounting Principle			-		-		-		(855)

Net Income		$	20,790	$	9,526	$	45,262	$	23,168

Basic Earnings Per Share:
	Income Before Accounting Change		$0.58		$0.27		$1.27		$0.76
	Cumulative Effect of Adoption of Accounting Principle		-		-		-		(0.03)
	Net Income		$0.58		$0.27		$1.27		$0.73

Diluted Earnings Per Share:
	Income Before Accounting Change		$0.56		$0.26		$1.23		$0.74
	Cumulative Effect of Adoption of Accounting Principle		-		-		-		(0.03)
	Net Income		$0.56		$0.26		$1.23		$0.71

Weighted Average Common Shares Outstanding:
	Basic		35,671,456		35,053,171		35,610,454		31,614,921
	Diluted		36,825,281		36,087,726		36,719,929		32,558,360

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,
			2004		2003
			(in thousands)
Current Assets
	Cash		$	1,086	$	1,277
	Accounts receivable			53,915		58,543
	Inventories, at average cost			23,698		31,418
	Under-recovered purchased gas costs			1,745		1,107
	Hedging asset - SFAS No. 133			100		3,693
	Deferred income tax assets			6,773		-
	Other			4,053		4,272
		Total current assets		91,370		100,310

Investments				13,295		13,840

Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method			1,325,351		1,201,917
	Gas distribution systems			205,556		203,793
	Gas in underground storage			32,254		33,256
	Other			33,142		30,038
				1,596,303		1,469,004
	Less: Accumulated depreciation, depletion and amortization			738,020		706,720
				858,283		762,284

Other Assets				15,490		14,276

Total Assets			$	978,438	$	890,710

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,
			2003		2002
			(in thousands)
Current Liabilities
	Accounts payable		$	63,993	$	54,186
	Taxes payable			4,695		5,692
	Interest payable			2,211		2,338
	Customer deposits			5,304		5,277
	Hedging liability - SFAS No. 133			28,646		20,997
	Regulatory liability - hedges			-		2,137
	Other			2,742		4,441
		Total current liabilities		107,591		95,068

Long-Term Debt				278,000		278,800

Other Liabilities
	Deferred income tax liabilities			173,397		147,295
	Other			27,007		15,859
				200,404		163,154

Commitments and Contingencies

Minority Interest in Partnership				12,483		12,127

Shareholders' Equity
	Common stock, $.10 par value; authorized 75,000,000 shares, issued 37,225,584 shares			3,723		3,723
	Additional paid-in capital			124,680		123,519
	Retained earnings			292,147		246,885
	Accumulated other comprehensive income (loss)			(24,201)		(12,520)
	Less:	Common stock in treasury, at cost, 1,058,245 shares at June 30, 2004 and 1,307,995 shares at December 31, 2003		(11,789)		(14,571)
		Unamortized cost of 418,125 restricted shares at June 30, 2004 and 421,617 restricted shares at December 31, 2003 issued under stock incentive plans		(4,600)		(5, 475)
				379,960		341,561

Total Liabilities and Shareholders' Equity			$	978,438	$	890,710

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,
			2004		2003
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	45,262	$	23,168
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		34,372		27,668
		Deferred income taxes		26,582		14,724
		Ineffectiveness of cash flow hedges		1,239		(556)
		Gain on sale of property, plant & equipment		(1,534)		-
		Equity in (income) loss of NOARK partnership		545		(1,444)
		Minority interest in partnership		356		799
		Cumulative effect of adoption of accounting principle		-		855
	Change in operating assets and liabilities:
		Accounts receivable		4,628		3,941
		Inventories		5,957		4,898
		Under-recovered purchased gas costs		(638)		(3,664)
		Accounts payable		6,482		2,303
		Taxes payable		(997)		(2,209)
		Other operating assets and liabilities		(1,781)		(175)
	Net cash provided by operating activities			120,473		70,308

Cash Flows From Investing Activities
	Capital expenditures			(124,234)		(80,468)
	Distribution from NOARK partnership			-		2,500
	Proceeds from sale of other property, plant & equipment			1,906		-
	Increase in gas stored underground			-		(1,705)
	Other items			(74)		(479)
	Net cash used in investing activities			(122,402)		(80,152)

Cash Flows From Financing Activities
	Issuance of common stock			-		103,213
	Payments on revolving long-term debt			(210,300)		(184,900)
	Borrowings under revolving long-term debt			209,500		90,300
	Debt issuance costs			(1,514)		-
	Change in bank drafts outstanding			898		218
	Proceeds from exercise of common stock options			3,154		1,292
	Minority interest contributions			-		44
	Net cash provided by financing activities			1,738		10,167

Increase (decrease) in cash				(191)		323
Cash at beginning of year				1,277		1,690
Cash at end of period			$	1,086	$	2,013

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)

							Unamortized	Accumulated
			Additional				Restricted	Other
	Common Stock		Paid-In		Retained	Treasury	Stock	Comprehensive
	Shares	Amount	Capital		Earnings	Stock	Awards	Income (Loss)	Total
				(in thousands)
Balance at December 31, 2003	37,226	$3,723	$123,519		$246,885	($14,571)	($5,475)	($12,520)	$341,561
Comprehensive income:
Net Income	-	-	-		45,262	-	-	-	45,262
Change in value of derivatives	-	-	-		-	-	-	(11,681)	(11,681)
Total comprehensive income	-	-	-		-	-	-	-	33,581

Exercise of stock options	-	-	1,106		-	2,743	-	-	3,849
Issuance of restricted stock	-	-	55		-	39	(94)	-	-
Amortization of restricted stock	-	-	-		-	-	969	-	969

Balance at June 30, 2004	37,226	$3,723	$124,680		$292,147	($11,789)	($4,600)	($24,201)	$379,960


RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

		For the three months ended				For the six months ended
		June 30,				June 30,
			2004		2003		2004		2003
			(in thousands)				(in thousands)

Balance, beginning of period		$	(19,517)	$	(21,342)	$	(12,520)	$	(17,358)
	Current period reclassification to earnings		4,946		5,075		7,641		16,963
	Current period change in derivative instruments		(9,630)		(10,032)		(19,322)		(25,904)
Balance, end of period		$	(24,201)	$	(26,299)	$	(24,201)	$	(26,299)

The accompanying notes are an integral part of the financial statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

June 30, 2004

(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, 2003 (the "2003 Annual Report on Form 10-K").

(2) ISSUANCE OF COMMON STOCK

In the first quarter of 2003, the Company completed the sale of 9,487,500 shares of its common stock under a registration statement filed with the Securities and Exchange Commission in December 2002. Aggregate net proceeds from the equity offering of $103.1 million were used to pay outstanding borrowings under the Company's revolving credit facility. The Company is reborrowing the repaid amounts under the credit facility as necessary to fund the acceleration of the development of the Company's Overton Field in East Texas and for general corporate purposes.

(3) GAS AND OIL PROPERTIES

The Company follows the full cost method of accounting for the exploration, development and acquisition of gas and oil reserves. Under this method, all costs (productive and nonproductive) directly attributable to these activities, including salaries, benefits and other internal costs, are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. The Company excludes all costs of unevaluated properties from immediate amortization. The Company's unamortized costs of natural gas and oil properties are limited to the sum of the future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If the Company's unamortized costs in natural gas and oil properties exceed this ceiling amount, it will record a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to e
arnings. At June 30, 2004, the Company's net book value of natural gas and oil properties did not exceed the ceiling amount. Decreases in market prices from June 30, 2004 levels, as well as changes in production rates, levels of reserves, and the evaluation of costs excluded from amortization, could result in future ceiling test impairments.

141 and 142 is being considered as to whether mineral interest use rights in gas and oil properties are intangible assets. Under this interpretation, mineral interest use rights for both undeveloped and developed leaseholds would be classified as intangible assets, separate from gas and oil properties. The classification as an intangible asset would not affect how these items are accounted for under the full cost method of accounting with respect to the calculation of depreciation, depletion and amortization or the calculation of the ceiling test of gas and oil properties. This interpretation would not affect our results of operations or cash flows. The Company had undeveloped leasehold of approximately $19.7 million and $16.9 million at June 30, 2004 and December 31, 2003, respectively, that would be classified as "intangible undeveloped leasehold" if this interpretation were applied. Southwestern also had developed leasehold of approximately $10.4 million and $9.3 million at June
30, 2004 and December 31, 2003, respectively, that would be classified as "intangible developed leasehold" if it applied this interpretation. The portion of developed leasehold that would be reclassified represents the costs of developed leaseholds acquired or transferred to the full cost pool subsequent to June 30, 2001, the effective date of FAS 141. Additionally, FAS 142 requires that certain disclosures be made for all intangible assets. The Company has not made the disclosures set forth under FAS 142 related to the use rights of mineral interests.

The Financial Accounting Standards Board (FASB) has issued a proposed FASB Staff Position (FSP 142-b) to address the application of FAS 141 to
the oil and gas industry. If adopted as written, the proposed FSP would confirm the Company's historical treatment of these costs. Southwestern will continue to monitor this issue.

(4) 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 shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restricted shares of common stock. Options for 2,287,333 shares at June 30, 2004, with a weighted average exercise price of $10.68, and options for 2,500,270 shares at June 30, 2003, with a weighted average exercise price of $10.10, were included in the calculation of diluted shares. Options for 70,984 shares, with an average exercise price of $17.19 per share at June 30, 2003, were not included in the calculation of diluted shares because they would have had an antidilutive effect. Restricted stock shares included in the calculation of diluted shares were 187,031 and 498,664 at June 30,
2004 and 2003, respectively.

(5) DEBT

Debt balances as of June 30, 2004 and December 31, 2003 consisted of the following:

In January 2004, the Company arranged a new $300 million three-year unsecured revolving credit facility with a group of banks to replace its previous $125 million credit facility that was scheduled to expire in July 2004. The Company also has access to an additional $15 million of borrowing capacity under a separate three-year unsecured credit facility that was entered into at the same time. The interest rate on each of the credit facilities is calculated based upon our debt rating and is currently 125 basis points over the current London Interbank Offered Rate (LIBOR). The credit facilities contain covenants which impose certain restrictions on the Company. Under the credit agreements, 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 at least 3.5 or above. There are
also restrictions on the ability of the Company's subsidiaries to incur debt. The Company was in compliance with its debt agreements at June 30, 2004.

(6) DERIVATIVE AND HEDGING ACTIVITIES

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, was adopted by the Company on January 1, 2001. FAS 133 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, 2004, the Company's net liability related to its cash flow hedges was $39.4 million. Additionally, at June 30, 2004, the Company had recorded a net of tax cumulative loss to other comprehensive income (equity section of the balance sheet) of $23.7 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.
The amount estimated to be reclassified to earnings as a loss over the next 12
months is approximately $28.6 million. The changes in accumulated other
comprehensive loss related to derivatives were losses of $7.4 million ($4.7
million after tax) and

$8.0 million ($5.0 million after tax) for the three
months ended June 30, 2004 and 2003, respectively, and $18.5 million ($11.7
million after tax) and $14.4 million ($8.9 million after tax) for the six months
ended June 30, 2004 and 2003, respectively. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the adoption of FAS 133.

(7) 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 2003 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 and the cumulative effect of adoption of accounting principle 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.

	June 30,	December 31,
	2004	2003
	(in thousands)
Senior notes:
6.70% Series due 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 (2.27% at June 30, 2004 and 2.67% at December 31, 2003) unsecured revolving credit arrangements	53,000	53,800
Total debt	$ 278,000	$ 278,800

	Exploration
	And			Gas
	Production			Distribution	Marketing	Other			Total
	(in thousands)

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	753,866		154,648		25,905	37,246	(2)	971,665		(2)
Capital expenditures	66,428	(3)	1,241		1	532		68,202		(3)

Three months ended June 30, 2003:
Revenues from external customers	$34,211		$20,609		$11,667	$ --		$66,487
Intersegment revenues	9,278		28		38,230	112		47,648
Operating income (loss)	21,476		(2,108)		536	42		19,946
Depreciation, depletion and amortization expense	12,117		1,534		12	23		13,686
Interest expense ⁽¹⁾	2,549		1,092		2	268		3,911
Provision (benefit) for income taxes ⁽¹⁾	6,966		(1,230)		203	(102)		5,837
Assets	583,429		150,176		17,709	37,465	(2)	788,779		(2)
Capital expenditures	46,784		3,099		2	214		50,099

(1) Interest expense and the provision 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.

(3) Exploration and Production capital expenditures include ($5.5) million and $2.6 million for the three- and six-month
periods ended June 30, 2004, respectively, relating to the effects of accrued expenditures.

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, debt issuance costs 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.

(8) INTEREST AND INCOME TAXES PAID

The following table provides interest and income taxes paid during each period presented. Interest payments in 2003 include amounts paid for the settlement of interest rate hedges.


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	753,866		154,648	25,905	37,246	(2)	971,665	(2)
Capital expenditures	123,011	(3)	3,180	1	647		126,839	(3)

Six months ended June 30, 2003:
Revenues from external customers	$62,820		$78,049	$24,273	$ --		$165,142
Intersegment revenues	20,405		95	73,544	224		94,268
Operating income	40,413		5,897	1,227	83		47,620
Depreciation, depletion and amortization expense	22,931		3,068	24	46		26,069
Interest expense ⁽¹⁾	6,272		2,073	2	511		8,858
Provision for income taxes ⁽¹⁾	12,462		1,410	466	386		14,724
Assets	583,429		150,176	17,709	37,465	(2)	788,779	(2)
Capital expenditures	75,232		4,940	2	294		80,468

(9) MINORITY INTEREST IN PARTNERSHIP

In 2001, the Company's subsidiary, Southwestern Energy Production Company (SEPCO) formed a limited partnership, Overton Partners, L.P., with an investor to drill and complete 14 development wells in SEPCO's Overton Field located in Smith County, Texas. Because SEPCO is the sole general partner and owns a majority interest in the partnership, the operating and financial results are consolidated with the Company's exploration and production results and the investor's share of the partnership activity is reported as minority interest in the financial statements.

(10) 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, 2004 and December 31, 2003, the outstanding principal for these notes was $68.0 million and $69.0 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 $1.0 million in costs have been incurred in 2004. This contract expires in 2014.

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 have arisen 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.

(11) ACCOUNTING FOR STOCK-BASED COMPENSATION

The Company's stock-based employee compensation plan 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 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," to stock-based employee compensation.

	For the six months ended
	June 30,
	2004		2003
	(in thousands)

Interest payments	$	8,695	$	9,007
Income tax payments	$	--	$	--

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions for all periods presented: no dividend yield; expected volatility of 47.1%; risk-free interest rate of 3.7%; and expected lives of 6 years for all option grants. There were 7,000 options granted in the first six months of 2004 and no options granted in the first six months of 2003.

(12) 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, 2004 and 2003:

	For the three months ended		For the six months ended
	June 30,		June 30,
	2004	2003	2004	2003
	(in thousands, except per share)

Net Income, as reported	$ 20,790	$ 9,526	$ 45,262	$ 23,168
Add back: Amortization of restricted stock	304	435	610	869
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(595)	(716)	(1,192)	(1,431)
Pro forma net income	$ 20,499	$ 9,245	$ 44,680	$ 22,606

Earnings per share:
Basic-as reported	$ 0.58	$ 0.27	$ 1.27	$ 0.73
Basic-pro forma	0.57	0.26	1.25	0.72
Diluted-as reported	0.56	0.26	1.23	0.71
Diluted-pro forma	0.56	0.26	1.22	0.69

	Pension Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2004	2003	2004	2003
	(in thousands)

Service cost	$ 601	$ 543	$ 1,202	$ 1,086
Interest cost	923	915	1,846	1,830
Expected return on plan assets	(1,136)	(902)	(2,272)	(1,804)
Amortization of prior service cost	111	111	222	222
Amortization of net loss	58	166	117	332
Net periodic benefit cost	$ 557	$ 833	$ 1,115	$ 1,666

We currently expect to contribute $1.9 million to our pension plan in 2004, which is down from our original estimate at the end of 2003 of $2.4 million. As of June 30, 2004, $0.8 million of contributions have been made.

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

The following updates information as to the Company's financial condition provided in our 2003 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, 2004, and the comparable periods of 2003. For definitions of commonly used gas and oil terms as used in this Form 10-Q, please refer to the "Glossary of Certain Industry Terms" provided in our 2003 Annual Report on Form 10-K.

OVERVIEW

Southwestern Energy Company is an 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. We operate our business in three segments: Exploration and Production, Natural Gas Distribution and Natural Gas Marketing.

Our financial results depend on a number of factors, including in particular natural gas and oil prices, our ability to find and produce natural gas and oil, our ability to control costs, the seasonality of our customers' need for natural gas and our ability to market natural gas and oil on economically attractive terms to our customers, all of which are dependent upon numerous factors beyond our control such as economic, political and regulatory developments and competition from other energy sources. There has been significant price volatility in the natural gas and crude oil market in recent years. The volatility was attributable to a variety of factors impacting supply and demand, including weather conditions, political events and economic events we cannot control or predict.

Our business strategy is focused on providing long-term growth in the net asset value of our business. We prepare economic analyses for each of our drilling and acquisition opportunities and rank them based upon the expected present value created for each dollar invested, which we refer to as PVI. The present value of the future expected cash flows for each project is determined using a 10% discount rate. We target creating at least $1.30 of discounted pre-tax present value for each dollar we invest in our Exploration and Production, or E&P, business. We are also focused on creating and capturing additional value beyond the wellhead through our natural gas distribution, marketing and transportation businesses.

Quarter Ended June 30, 2004 Compared with Quarter Ended June 30, 2003

We reported net income of $20.8
million, or $0.56 per share on a diluted basis, on revenues of $96.4 million for
the three months ended June 30, 2004, compared to $9.5 million, or $0.26 per
share, on revenues of $66.5 million for the same period in 2003. The increase in
net income was primarily a result of increased production volumes and higher
realized natural gas and oil prices in our E&P segment. Operating income for our
E&P segment was $37.5 million for the quarter ended June 30, 2004, up from $21.5
million for the same period in 2003. Our gas distribution segment incurred an
operating loss of $1.4 million for the three months ended June 30, 2004,
compared to a

loss of $2.1 million for the same period in 2003. The
decrease in operating loss for our gas distribution segment resulted primarily
from an increase in approved rates charged to customers that were implemented in
October 2003.

In the second quarter of 2004, our gas and oil production continued to increase, reaching 12.6 Bcfe, up from 10.1 Bcfe in the second quarter of 2003 and 11.4 Bcfe in the first quarter of 2004. The increase in 2004 production primarily resulted from an increase in production from our Overton Field in East Texas due to the accelerated development of the field and from increased production from our River Ridge discovery in New Mexico.

Our capital investments totaled $68.2 million for the second quarter of 2004, up from $50.1 million in the second quarter of 2003. We invested $66.4 million in our E&P segment in the second quarter of 2004, compared to $46.8 million for the same period in 2003.

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

Net income for the six months ended June 30, 2004 was $45.3 million, or $1.23 per share on a diluted basis, on revenues of $216.2 million, compared to net income of $23.2 million, or $0.71 per share, on revenues of $165.1 million for the same period in 2003. Operating income for our E&P segment was $70.9 million for the first six months of 2004, up from $40.4 million for the same period in 2003. The increases were due to increased production volumes and higher prices realized for our production. Operating income for our gas distribution segment was $7.4 million for the first six months of 2004, compared to $5.9 million for the same period in 2003. The increase in operating income for our gas distribution segment resulted primarily from increased rates implemented in October 2003. Our cash flow from operating activities was $120.5 million for the six months ended June 30, 2004, compared to $70.3 million for the same period in 2003. The increase in operating ca
sh flow was primarily due to the improved operating results of our E&P segment.

In the first six months of 2004, our gas and oil production increased to 24.0 Bcfe, up from 18.9 Bcfe in the same period of 2003. The increase in 2004 production primarily resulted from an increase in production from our Overton Field in East Texas due to the accelerated development of the field and from increased production in the Arkoma basin and from our River Ridge discovery in New Mexico.

Our capital investments totaled $126.8 million for the first six months of 2004, up from $80.4 million in the first six months of 2003. We invested $123.0 million in our E&P segment in the first six months of 2004, compared to $75.2 million for the same period in 2003. Capital investments currently planned for calendar year 2004 total $254.0 million, including $244.5 million for our E&P segment. The expected capital investments for 2004 include $14.4 million that was incurred in July for the acquisition of additional working interests in our River Ridge discovery in New Mexico.

RESULTS OF OPERATIONS

Exploration and Production

	Postretirement Benefits
	For the three months ended June 30,		For the six months ended June 30,
	2004	2003	2004	2003
	(in thousands)

Service cost	$ 44	$ 35	$ 87	$ 70
Interest cost	63	60	126	119
Expected return on plan assets	(11)	(9)	(21)	(18)
Amortization of net loss	29	22	51	44
Amortization of transition obligation	18	21	43	43
Net periodic benefit cost	$ 143	$ 129	$ 286	$ 258

Revenues, Operating Income and Production

Revenues. Revenues for our E&P segment were up 51% to $65.9 million for the three months ended June 30, 2004 and up 50% to $124.9 million for the six months ended June 30, 2004, as compared to the respective periods in 2003. The increases were primarily due to increased production volumes and higher gas and oil prices realized for our production.

Operating Income. Operating income for the E&P segment was up 74% to $37.5 million for the second quarter of 2004 and up 75% to $70.9 million for the six months ended June 30, 2004, compared to $21.5 million and $40.4 million for the same respective periods in 2003. The increase in operating income resulted from the increase in revenues, partially offset by increased operating costs and expenses.

Production. Gas and oil production during the second quarter of 2004 was 12.6 billion cubic feet (Bcf) equivalent, up 25% from 10.1 Bcf equivalent in the second quarter of 2003. Gas and oil production was 24.0 Bcf equivalent for the first six months of 2004, compared to 18.9 Bcf equivalent for the same period of 2003. The comparative increases in production primarily resulted from an increase in production from our Overton Field in East Texas due to the accelerated development of the field, and increased production in the Arkoma basin and from our River Ridge

discovery in New Mexico. Gas production was 11.8 Bcf for the second quarter of 2004 up from 9.3 Bcf for the second quarter of 2003. Gas production was 22.3 Bcf for the first six months of 2004 compared to 17.4 Bcf for the same period of 2003. Intersegment sales to our gas distribution systems were 3.3 Bcf during the six months ended June 30, 2004, compared to 3.5 Bcf for the same period in 2003. Our oil production was 140 thousand barrels (MBbls) during the second quarter of 2004 and 292 MBbls for the first six months of 2004, up from 139 MBbls and 264 MBbls for the same periods of 2003, respectively.

Commodity Prices

The average price realized for our gas production, including the effect of hedges, was $5.25 per thousand cubic feet (Mcf) for the three months ended June 30, 2004, up from $4.28 per Mcf for the same period of 2003. For the first six months of 2004, we received an average gas price of $5.09 compared to $4.22 for the same period of 2003. The changes in the average price realized primarily reflect changes in average annual spot market prices and the effects of our price hedging activities. Our hedging activities lowered our average gas price realized during the first six months of 2004 by $0.50 per Mcf, compared to $1.51 per Mcf during the same period of 2003. Additionally, we have historically received demand charges related to sales made to our utility segment, which have increased the average gas price realized.

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 2004, we have hedges in place for 16.5 Bcf of gas production and for 2005 we have 30.0 Bcf of our future gas production hedged. See Part I, Item 3 of this Form 10-Q for additional information regarding the Company's commodity price risk hedging activities.

We realized an average price of $28.55 per barrel for our oil production, including the effect of hedges, during the six months ended June 30, 2004, up from $27.54 per barrel for the same period of 2003. The average price we received for our oil production in the first half of 2004 and 2003 was reduced by $6.86 per barrel and $2.80 per barrel, respectively, due to the effects of our hedging activities. For the remainder of 2004, we have hedged 207,000 barrels of our oil production at an average NYMEX price of $28.05 per barrel.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment were $0.39 for both the second quarter of 2004 and the first six months of 2004, compared to $0.36 and $0.39 for the same respective periods in 2003. Taxes other than income taxes per Mcfe were $0.28 and $0.27 for the second quarter and first six months of 2004, respectively, compared to $0.23 and $0.25 for the same periods in 2003. The increases in severance taxes per Mcfe in 2004 are 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. General and administrative expenses per Mcfe
were $0.35 and $0.37 during the second quarter and for the first six months of
2004, down

from $0.40 and $0.42 for the same periods in 2003. The
decreases in per unit general and administrative expenses in 2004 are primarily
due to the increase in our production volumes.

We utilize the full cost method of accounting for costs related to our 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. The Company excludes all costs of unevaluated properties from immediate amortization. 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 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 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 impa
ct of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. At June 30, 2004, our unamortized costs of gas and oil properties did not exceed this ceiling amount. Our standardized measure at June 30, 2004 was calculated based upon quoted market prices of $5.76 per Mcf for gas and $37.05 per barrel for oil, adjusted for market differentials. A decline in gas and oil prices from the June 30, 2004 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.

Natural Gas Distribution

	For the three months		For the six months
	ended June 30,		ended June 30,
	2004	2003	2004	2003

Revenues (in thousands)	$65,872	$43,489	$124,943	$83,225
Operating income (in thousands)	$37,452	$21,476	$70,881	$40,413

Gas production (MMcf)	11,781	9,259	22,296	17,360
Oil production (MBbls)	140	139	292	264
Total production (MMcfe)	12,621	10,093	24,048	18,944

Average gas price per Mcf, including hedges	$5.25	$4.28	$5.09	$4.22
Average gas price per Mcf, excluding hedges	$5.82	$5.14	$5.59	$5.73
Average oil price per Bbl, including hedges	$28.68	$27.40	$28.55	$27.54
Average oil price per Bbl, excluding hedges	$37.09	$28.80	$35.41	$30.34

Average unit costs per Mcfe
Lease operating expenses	$0.39	$0.36	$0.39	$0.39
General & administrative expenses	$0.35	$0.40	$0.37	$0.42
Taxes, other than income taxes	$0.28	$0.23	$0.27	$0.25
Full cost pool amortization	$1.18	$1.17	$1.18	$1.17

Revenues and Operating Income

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, 2004 increased 12% and 8%,

respectively, from the comparable periods of 2003 due
primarily to increased cost of gas supplies caused by higher gas prices and to
the effects of a $4.1 million annual rate increase implemented in October 2003.

Operating Income. The seasonal operating loss for our gas distribution segment decreased $0.7 million in the second quarter of 2004 and operating income increased $1.5 million in the first six months of 2004, as compared to the same periods of 2003. The changes in operating income were primarily due to the rate increase implemented in late 2003, combined with an increase in the number of customers served, partially offset by decreased volumes sold due to warmer than normal weather. Weather during the first half of 2004 was 5% warmer than normal and 9% warmer than the same period in 2003.

Deliveries and Rates

The utility systems delivered 3.9 Bcf and 13.7 Bcf to sales and end-use transportation customers during the three- and six-month periods ended June 30, 2004, compared to 3.8 Bcf and 14.5 Bcf for the same periods in 2003. The decrease in deliveries during the first half of 2004 was primarily due to the effects of warmer weather and customer conservation brought about by high gas prices. 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 half of 2004 was reflected in the utility segment's average rate for its sales which increased to $8.73 per Mcf, up from $7.34 per Mcf for the same period in 2003. The fluctuations in the average sales rate reflect changes in the average cost of gas purchased for delivery to our customers, which are passed through to customers under automatic adjustmen
t clauses. Our utility segment hedged 3.8 Bcf of gas purchases in the first six months of 2004 which had the effect of decreasing its total gas supply cost by $0.1 million. In the first half of 2003, our utility hedged 2.7 Bcf of its gas supply which decreased its total gas supply cost by $7.5 million.

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 the second quarter 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 payroll.

Marketing and Transportation

Marketing

	For the three months		For the six months
	ended June 30,		ended June 30,
	2004	2003	2004	2003

Revenues (in thousands)	$23,012	$20,637	$84,271	$78,144
Gas purchases (in thousands)	$12,994	$11,467	$54,342	$49,634
Operating costs and expenses (in thousands)	$11,446	$11,278	$22,547	$22,613
Operating income (loss) (in thousands)	($1,428)	($2,108)	$7,382	$5,897

Deliveries (Bcf)
Sales and end-use transportation	3.9	3.8	13.7	14.5
Off-system transportation	-	0.1	1.0	0.1

Customers at period-end	140,227	137,690	140,227	137,690
Average sales rate per Mcf	$11.06	$9.74	$8.73	$7.34
Heating weather - degree days	261	279	2,322	2,554
Percent of normal	84%	90%	95%	104%

Our operating income from natural gas marketing was $0.8 million on revenues of $72.4 million in the second quarter of 2004, and $1.7 million on revenues of $133.7 million for the first six months of 2004, compared to $0.5 million on revenues of $49.9 million and $1.2 million on revenues of $97.8 million in the same respective periods of 2003. The increase in revenues for the three- and six-month periods ended June 30, 2004, as compared to the same periods in the prior year, was primarily due to an increase in affiliated volumes marketed. These increases were largely offset by comparable increases in purchased gas costs. We marketed 10.1 Bcf of affiliated gas in the second quarter of 2004, representing 77% of total volumes marketed, compared to 7.5 Bcf, or 74% of total volumes marketed, for the same period in 2003. Affiliated gas marketed for the first six months of 2004 was 20.2 Bcf compared to 13.2 Bcf for the same period in 2003. 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.

Transportation

We recorded a pre-tax loss from operations related to our investment in the NOARK Pipeline System Limited Partnership (NOARK) of $0.7 million for the second quarter of 2004 and $0.5 million for the first six months of 2004, compared to
a pre-tax loss of $0.1 million for the second quarter of 2003 and pre-tax income
of $1.4 million for first six months of 2003. These amounts were recorded in other income (expense) in our income statement. The pre-tax loss in the second quarter of 2004 included adjustments to previous allocations of income and expense by the pipeline's operator. The pre-tax income in the first six months of 2003 included a gain of $1.3 million recognized by the Company on the sale of a 28-mile portion of NOARK's pipeline located in Oklahoma that had limited strategic value to the overall system. Sales proceeds to NOARK were $10.0 million and our share of the proceeds was $2.5 million.

Other Revenues

Revenues and operating income for the first six months of 2004 and 2003 include pre-tax gains of $3.0 million and $2.7 million, respectively, related to the sale of gas in storage inventory. Additionally, the second quarter of 2004 included a gain of $1.5 million related to the sale of undeveloped real estate.

Interest Expense

Interest costs, net of capitalization, increased 1% in the second quarter of 2004 and decreased 6% for the first six months of 2004, compared to the same periods in 2003. During the second quarter of 2004, higher interest costs that resulted from increased average borrowings were offset by an increase in capitalized interest. Interest costs decreased for the six months ended June 30, 2004, as compared to the same period in 2003, primarily due to lower average borrowings and increased capitalized interest. Our average borrowings decreased during the second quarter of 2003 as net proceeds of $103.1 million from the Company's equity offering were initially used to pay down our revolving credit facility. We are reborrowing the repaid amounts under the credit facility as necessary to fund the acceleration of the development of the Company's Overton Field in East Texas and for general corporate purposes. Changes in capitalized interest are primarily due to the level of cost
s excluded from amortization in our E&P segment.

Income Taxes

Our effective tax rate for the six months ended June 30, 2004 was 37.0% compared to 38.0% for the same period in 2003. 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 quarter of 2004 and $1.1 million for the first six months of 2004 compared to pension expense of $0.8 million and $1.7 million, respectively, for the same periods in 2003. 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 $1.9 million to our pension plan in 2004, which is down from our original estimate at the end of 2003 of $2.4 million. As of June 30, 2004, $0.8 million of contributions have been made. For further information regarding our pension plans, we refer you to Note 12 of the financial statements in this Form 10-Q and "Critical Accounting Policies" below.

LIQUIDITY AND CAPITAL RESOURCES

We depend on internally-generated funds and our unsecured revolving credit facilities (discussed below under "Financing Requirements") as our primary sources of liquidity. We may borrow up to $315.0 million under our revolving credit facilities from time to time. As of June 30, 2004, we had $53.0 million of indebtedness outstanding under our revolving credit facilities. During 2004 we expect to draw on a portion of the funds available under our credit facilities to fund our planned capital expenditures (discussed below under "Capital Expenditures"). In December 2002, we filed a shelf registration statement with the SEC pursuant to which we may from time to time, subject to market conditions, publicly offer equity, debt or other securities.

Net cash provided by operating activities
was $120.5 million in the first six months of 2004, compared to $70.3 million
for the same period of 2003. The primary components of cash provided from
operations are 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 2004, cash provided by operating activities provided
95% of our requirements for capital expenditures. For the same period of 2003,
cash provided by operating activities supplied 87% these requirements.

Our cash flow from operating activities is highly dependent upon market prices that we receive for our gas and oil production. The price received for our production is also influenced by our commodity hedging activities, as more fully discussed in Note 6 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 2004 were $126.8 million, including $2.6 million of accrued expenditures, compared to $80.5 million for the same period in 2003. We currently expect our capital investments for calendar year 2004 to be approximately $254.0 million including $244.5 million of capital investments in our E&P segment. Our planned capital investments for 2004 include approximately $14.4 million that was incurred in July for the acquisition of additional working interests in our River Ridge discovery in New Mexico. Our 2004 capital investment program is expected to be funded through cash flow from operations and, as necessary, borrowings under our revolving credit facilities. We may adjust our level of future capital investments dependent upon the level of cash flow generated from operations.

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, and 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. This debt financed a portion of the original cost to construct the NOARK Pipeline. Our share of the guarantee is 60% and we are allocated 60% of the interest expense. At June 30, 2004, the outstanding principal amount of these notes was $68.0 million and our share of the guarantee was $40.8 million. The notes were issued in June 1998 and 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 2004 a
nd do not expect to advance any funds during the remainder of 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 a pre-tax loss of $0.7 million for the second quarter of 2004 and $0.5 million for the first six months of 2004, compared to
a pre-tax loss of $0.1 million for the second quarter of 2003 and and pre-tax
income of $1.4 million for the first six months of 2003. The pre-tax loss in the second quarter of 2004 included adjustments to previous allocations of income and expense by the

pipeline's operator. Our share of the pre-tax income in the first half of 2003 included a gain of $1.3 million from NOARK's sale of a 28-mile portion of its pipeline located in Oklahoma that had limited strategic value to the overall system. Sales proceeds to NOARK were $10.0 million and our share of the proceeds was $2.5 million. We believe that we will be able to continue to improve the operating results of the NOARK project and expect our investment in NOARK to be realized over the life of the system.

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, 2004 are as follows:

Contractual Obligations

	For the three months ended		For the six months ended
	June 30,		June 30,
	2004	2003	2004	2003

Revenues (in thousands)	$72,435	$49,897	$133,695	$97,817
Operating income (in thousands)	$811	$536	$1,698	$1,227
Gas volumes marketed (Bcf)	13.1	10.2	25.4	18.7

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

(2) 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, 2004 totaled 1.6 Bcf, comprised of 0.8 Bcf in less than one year, 0.5 Bcf in one to three years, 0.2 Bcf in three to five years and 0.1 Bcf in more than 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.

(3) Our utility segment has commitments for approximately $99.8 million of demand charges on firm non-cancelable 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 $5.7 million of demand transportation charges.

(4) Our significant other contractual obligations include approximately $1.6 million for funding of benefit plans, approximately $1.0 million of various information technology support and data subscription agreements, $0.5 million for drilling rig commitments, and approximately $0.4 million of land leases.

We refer you to "Financing Requirements" below for a discussion of the terms of our long-term debt.

Contingent Liabilities or Commitments

We have the following commitments and
contingencies that could create, increase or accelerate our liabilities.
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

$2.2 million in 2004, of which $1.1 million has
been recorded in the first half of 2004. For further information regarding our
pension plans, we refer you to Note 12 of the financial statements in this Form 10-Q and "Critical Accounting Policies" below.

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, 2004 the outstanding principal of these notes was $68.0 million and our share of the guarantee was $40.8 million. The notes require semi-annual principal payments of $1.0 million.

Financing Requirements

Our total debt outstanding was $278.0 million at June 30, 2004 and $278.8 million at December 31, 2003. Of the total outstanding at June 30, 2004, $53.0 million was outstanding under our revolving credit facilities. In January 2004, the Company arranged a new $300 million three-year unsecured revolving credit facility with a group of banks to replace its previous $125 million credit facility that was scheduled to expire in July 2004. The Company also has access to an additional $15 million of borrowing capacity under a separate three-year unsecured credit facility that was entered into at the same time. The interest rate on each of the new facilities 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 BBB by Standard and Poor's and Ba2 by Moody's. Any downgrades in our public debt ratings could increase the cost of funds under our revolving credit faciliti
es.

Our revolving credit facilities contain 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 certain limitations on the amount of indebtedness that may be incurred by our subsidiaries. We were in compliance with the covenants of our debt agreements at June 30, 2004. Although we do not anticipate debt covenant violations, our ability to comply with our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market price
s for natural gas and oil.

At June 30, 2004, our capital structure consisted of 42% debt (excluding our several guarantee of NOARK's obligations), down from 45% at December 31, 2003, and our ratio of EBITDA to interest expense was 11.5. At June 30, 2004, the NOARK partnership had outstanding debt totaling $68.0 million. We and the other general partner of NOARK have severally guaranteed the principal and interest payments on the NOARK debt. Our share of the several guarantee is 60%.

Working Capital

We maintain access to funds that may be
needed to meet seasonal requirements through our credit facilities described
above. We had negative working capital of $16.2 million at June 30, 2004,
compared to positive working capital of $5.2 million at December 31, 2003. At
June 30, 2004, we

had $262.0 million of available borrowing capacity under our
revolving credit facilities. Current assets decreased by 9% in the first half of
2004 while current liabilities increased 13%. The decrease in current assets during the first half of 2004 was due primarily to a $7.7 million decrease in current inventories that resulted from the sale of gas stored underground combined with a $5.0 million decrease in accounts receivable caused primarily by the seasonality of the gas distribution segment's operations.
These decreases were partially offset by a $6.8 million increase in deferred
income tax assets primarily related to the current hedging liability. The change in current liabilities was primarily caused by an increase in our hedging liability and accounts payable. Under-recovered purchased gas costs for the Company's gas distribution segment were $1.7 million at June 30, 2004, compared to $1.1 million at December 31, 2003. Purchased gas costs are recovered from our utility customers in subsequent months through automatic cost of gas adjustment clauses included in the utility's filed rate tariffs. Changes in other current assets, accounts payable and other current liabilities are primarily due to the timing of expenditures and receipts. At June 30, 2004, we had a current hedging liability of $28.6 million recorded as a result of the provisions of FAS 133, compared to $21.0 million at December 31, 2003.

CRITICAL ACCOUNTING POLICIES

Natural Gas and Oil Properties

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis. Under these rules, all such costs (productive and nonproductive) directly attributable to these activities, including salaries, benefits and other internal costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. The Company excludes all costs of unevaluated properties from immediate amortization. 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 plus the lower of cost or market value of unproved properties. If the net capitalized costs of natural gas and oil properties exceed the ce
iling, we will record a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. The write-down may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling.

The risk that we will be required to write-down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are depressed or if there are substantial downward revisions in estimated proved reserves. Application of these rules during periods of relatively low natural gas or oil prices due to seasonality or other reasons, even if temporary, increases the probability of a ceiling test write-down. Based on natural gas and oil prices in effect on June 30, 2004, the unamortized cost of our natural gas and oil properties did not exceed the ceiling of proved natural gas and oil reserves. Natural gas pricing has historically been unpredictable and any significant declines could result in a ceiling test write-down in subsequent quarterly or annual reporting periods.

Natural gas and oil reserves used in the
full cost method of accounting cannot be measured exactly. Our estimate of
natural gas and oil reserves requires extensive judgments of reservoir
engineering data and is generally less precise than other estimates made in
connection with financial disclosures. Assigning monetary values to such
estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties
inherent in the disclosure are compounded by applying additional estimates of
the rates and timing of production and the costs that will be incurred in
developing and producing the reserves. We engage the services of an independent
petroleum consulting firm to audit reserves as estimated by our reservoir
engineers.

Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141), and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (FAS 142), were issued in June 2001 and became effective for the Company on July 1, 2001, and January 1, 2002, respectively. The Company understands the majority of the oil and natural gas industry did not change accounting and disclosures for mineral interest use rights (leasehold acquisition costs) upon the implementation of FAS 141 and 142. However, an interpretation of FAS 141 and 142 is being considered as to whether mineral interest use rights in gas and oil properties are intangible assets. Under this interpretation mineral interest use rights for both undeveloped and developed leaseholds would be classified as intangible assets, separate from gas and oil properties. The classification as an intangible asset would not affect how these items are accounted for under the ful
l cost method of accounting with respect to the calculation of depreciation, depletion and amortization or the calculation of the ceiling test of gas and oil properties. This interpretation would not affect our results of operations or cash flows. At June 30, 2004 and December 31, 2003, the Company had undeveloped leasehold of approximately $19.7 million and $16.9 million, respectively, that would be classified as "intangible undeveloped leasehold" if this interpretation were applied. Southwestern also had developed leasehold of approximately $10.4 million and $9.3 million at June 30, 2004 and December 31, 2003, respectively, that would be classified as "intangible developed leasehold" if it applied this interpretation. The portion of developed leasehold that would be reclassified represents the costs of developed leaseholds acquired or transferred to the full cost pool subsequent to June 30, 2001, the effective date of FAS 141. Additionally, FAS 142 requires that certain disclosures be made for all intang
ible assets. The Company has not made the disclosures set forth under FAS 142 related to the use rights of mineral interests.

Hedging

We use natural gas and crude oil swap
agreements and options and interest rate swaps to reduce the volatility of
earnings and cash flow, as well as to manage the price volatility of natural gas
purchases in our gas distribution segment, due to fluctuations in the prices of
natural gas and oil and in interest rates. Our policies prohibit speculation
with derivatives and limit swap agreements to counterparties with appropriate
credit standings. 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.

Our derivative instruments are accounted for under FAS
133 and are recorded at fair value in our financial statements. We utilize
market-based quotes from our hedge counterparties to value these open positions. These valuations are recognized as assets or
liabilities in our balance sheet and, to the extent an open position is an
effective cash flow hedge on equity production, gas marketing transactions or
interest rates, the offset is recorded in other comprehensive income. Results of
settled commodity hedging transactions are reflected in natural gas and oil
sales or in gas purchases. Results of settled interest rate hedges are reflected
in interest expense. Ineffective hedges, derivatives not qualifying for
accounting treatment as hedges, or ineffective portions of hedges are recognized
immediately in earnings. Future market price volatility could create significant
changes to the hedge positions recorded in our financial statements. We refer
you to "Quantitative and Qualitative Disclosures about Market Risk" in this Form
10-Q for additional information regarding our hedging activities.

Regulated Utility Operations

Our utility operations are subject to the rate regulation and accounting requirements of the Arkansas Public Service Commission (APSC). Allocations of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from those generally applied by non-regulated operations. Such allocations to meet regulatory accounting requirements are considered generally accepted accounting principles for regulated utilities provided that there is a demonstrated ability to recover any deferred costs in future rates.

During the ratemaking process, the regulatory commission may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as a regulatory asset and amortized to expense as they are recovered through rates. The regulatory commission has not required any unbundling of services, although some business customers are free to contract for their own gas supply. There are no regulations relating to unbundling of services currently anticipated; however, should any such regulation be proposed and adopted, certain of these assets may no longer meet the criteria for deferred recognition and, accordingly, a write-off of regulatory assets and stranded costs could be required.

Pension and Other Postretirement Benefits

We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation. Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For 2003, the assumed discount rate was 6.75% for the periodic benefit cost and 6.25% for the benefit obligations. The assumed expected return was 9.0% for 2003.

For 2004, we expect our pension expense to be approximately $2.2 million using an assumed discount rate of 6.25% and an assumed expected return of 9.0%. Pension expense of $1.1 million was recorded in the first six months of 2004.

Gas in Underground Storage

We record our gas stored in inventory that is 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 assets with the remaining stored gas reflected as a long-term asset. The quantity and average cost of gas in storage was 8.0 Bcf at $3.04 at June 30, 2004 and 10.4 Bcf at $3.33 at December 31, 2003.

The gas in inventory for the E&P segment is used primarily to supplement 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. Declines in the future market price of natural gas could result in a write down of our gas in storage carrying cost.

See further discussion of our significant accounting policies in Note 1 to the financial statements in our 2003 Annual Report on Form 10-K.

FORWARD-LOOKING INFORMATION

All statements, other than historical 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, and actual results or developments may differ materially from those in forward-looking statements. 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;

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;

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

the comparative cost of alternative fuels;

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 set forth under the heading "Risk Factors" in Part I, Item 1 of our 2003 Annual Report on Form 10-K which are incorporated by reference herein.

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 or incorporated by reference above occur, or should
underlying assumptions prove incorrect, our actual results and plans could
differ materially from those expressed in any forward-looking
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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISKS

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. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The 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 Risks

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 accounts for greater than 5% of accounts receivable at June 30, 2004. 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 NYMEX (New York Mercantile Exchange) 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
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 (billion cubic feet) and MBbls (thousand barrels), the weighted average contract prices, and the fair value by expected maturity dates. At June 30, 2004, the fair value of these financial instruments was a $39.4 million liability.

	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	$278,000	$ -	$178,000	$ -	$100,000
Operating leases⁽¹⁾	5,532	1,226	1,808	900	1,598
Unconditional purchase obligations⁽²⁾	-	-	-	-	-
Demand charges⁽³⁾	105,498	10,026	19,471	19,638	56,363
Other obligations⁽⁴⁾	3,824	3,689	110	25	-
	$392,854	$14,941	$199,389	$20,563	$157,961

At June 30, 2004, the Company had outstanding fixed-price basis differential swaps on 1.2 Bcf of 2004 gas production that did not qualify for hedge accounting treatment. The fair value of these differential swaps was an asset of $0.04 million at June 30, 2004.

At December 31, 2003, the Company had outstanding natural gas price swaps on total notional volumes of 8.0 Bcf at a weighted average price per Mcf of $4.21 in 2004 and 6.0 Bcf at a weighted average price per Mcf of $4.67 in 2005. Outstanding oil price swaps on 426 MBbls
were in place

that are yielding the Company an average price of $28.39 per
barrel during 2004. At December 31, 2003, the Company also had outstanding
natural gas price swaps on total notional gas purchase volumes of 3.8 Bcf in
2004 for which the Company paid an average fixed price of $5.34 per Mcf.

At December 31, 2003, the Company had collars in place on 23.6 Bcf in 2004 and 1.0 Bcf in 2005 of gas production. The 23.6 Bcf in 2004 has a weighted average floor and ceiling price of $3.85 and $6.48 per Mcf, respectively. The 1.0 Bcf in 2005 has a weighted average floor and ceiling price of $4.50 and $8.00 per Mcf, respectively.

Subsequent to June 30, 2004 and prior to July 26, 2004, we entered into additional derivative contracts to hedge gas production sales. During this time period we added price swaps on 1.6 Bcf of 2005 gas production at a weighted average price of $6.24 per Mcf, and costless collar hedges on 4.0 Bcf of 2005 gas production sales that have an average floor of $4.50 per Mcf and an average ceiling of $10.21 per Mcf. Additionally, we added price swaps on 1.0 Bcf of 2006 gas production at a weighted average price of $5.74 per Mcf, and costless collar hedges on 10.0 Bcf of 2006 gas production sales that have an average floor of $4.50 per Mcf and an average ceiling of $8.65 per Mcf.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and our Chief Financial Officer evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Our disclosure controls and procedures are the controls and other procedures that we designed to ensure that we record, process, summarize, and report in a timely manner the information we must disclose in reports that we file with the SEC. Our disclosure controls and procedures include our internal accounting controls. Based on the evaluation of our Chief Executive Officer and our Chief Financial Officer, our disclosure controls and procedures are effective. There were no changes in our internal controls or in other factors that could
materially affect these controls subsequent to the date of our evaluation.

PART II

OTHER INFORMATION

Items 1 - 3.

No developments required to be reported under Items 1 - 3 occurred during the quarter ended June 30, 2004.

Item 4. Submission of Matters to a Vote of Security Holders.

The Company held its Annual Meeting of Shareholders on May 12, 2004, for the purpose of electing Directors of the Company for the ensuing year and to vote on a proposal to adopt a new stock incentive plan for the compensation of officers, directors, and key employees of the Company and its subsidiaries. Holders of 32,435,568 shares (90.1% of total outstanding shares) voted in total.

Holders of 31,378,850 shares voted for the election of directors and holders of 1,056,718 shares withheld their votes. The Directors were elected with the number of shares voted as follows:

	Expected Maturity Date
	2004	2005

Production and Marketing
Natural Gas
Swaps with a fixed price receipt
Contract Volume (Bcf)	3.5	11.0
Weighted average price per Mcf	$3.99	$4.87
Fair value (in millions)	($8.2)	($12.2)
Price collars
Contract volume (Bcf)	13.0	19.0
Weighted average floor price per Mcf	$3.92	$4.51
Fair value of floor (in millions)	-	$2.1
Weighted average ceiling price per Mcf	$6.54	$7.01
Fair value of ceiling (in millions)	($8.5)	($9.8)
Swaps with a fixed price payment
Contract volume (Bcf)	0.1	-
Weighted average price per Mcf	$5.06	-
Fair value (in millions)	$0.1	-
Oil
Swaps with a fixed price receipt
Contract volume (MBbls)	0.2	0.2
Weighted average price per Bbl	$28.05	$30.05
Fair value (in millions)	($1.8)	($1.1)

Holders of 23,458,292 shares voted for a proposal to adopt a new stock incentive plan for the compensation of officers, directors, and key employees of the Company and its subsidiaries, 4,849,218 shares voted against, and 101,341 shares abstained.

Item 5.

No developments required to be reported under Item 5 occurred during the quarter ended June 30, 2004.

Item 6(a). Exhibits

(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.

(32.1) 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.

Item 6(b). Reports on Form 8-K

	Voted For	Withheld
Lewis E. Epley, Jr.	31,700,406	458,138
John Paul Hammerschmidt	31,294,210	864,334
Robert L. Howard	31,167,631	1,033,580
Harold M. Korell	33,197,713	814,665
Vello A. Kuuskraa	31,190,891	1,010,320
Kenneth R. Mourton	31,120,112	1,038,432
Charles E. Scharlau	31,224,452	934,092

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.

Date of Report	Item Number	Financial Statements Required to be Filed

July 23, 2004	5,7	No
July 8, 2004	9	No
June 30, 2004	9	No
June 7, 2004	9	No
June 3, 2004	5,7	No
May 4, 2004	9	No
April 29, 2004	12	No

			SOUTHWESTERN ENERGY COMPANY
			Registrant

Dated:	July 29, 2004	/s/ GREG D. KERLEY
		Greg D. Kerley
		Executive Vice President
		and Chief Financial Officer