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 March 31, 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 April 26, 2004
Common Stock, Par Value $0.10	36,077,888

PART I

FINANCIAL INFORMATION

1

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
		For the three months ended
		March 31,
			2004		2003
		(in thousands, except share/per share amounts)
Operating Revenues:
	Gas sales	$	101,019	$	77,707
	Gas marketing		9,186		12,606
	Oil sales		4,334		3,459
	Gas transportation and other		5,251		4,883
			119,790		98,655
Operating Cost and Expenses:
	Gas purchases - utility		31,532		27,048
	Gas purchases - marketing		8,063		11,558
	Operating expenses		9,712		9,046
	General and administrative expenses		8,010		7,883
	Depreciation, depletion and amortization		15,526		12,383
	Taxes, other than income taxes		3,640		3,063
			76,483		70,981
Operating Income			43,307		27,674
Interest Expense:
	Interest on long-term debt		4,421		4,927
	Other interest charges		512		385
	Interest capitalized		(548)		(365)
			4,385		4,947
Other Income (Expense)			321		1,422
Income Before Income Taxes, Minority Interest & Accounting Change			39,243		24,149
Minority Interest in Partnership			(399)		(765)
Income Before Income Taxes & Accounting Change			38,844		23,384
Provision for Income Taxes - Deferred			14,372		8,887
Income Before Accounting Change			24,472		14,497
Cumulative Effect of Adoption of Accounting Principle			-		(855)
Net Income		$	24,472	$	13,642
Basic Earnings Per Share:
	Income Before Accounting Change	$	0.69	$	0.51
	Cumulative Effect of Adoption of Accounting Principle		-		(0.03)
	Net Income	$	0.69	$	0.48
Diluted Earnings Per Share:
	Income Before Accounting Change	$	0.67	$	0.50
	Cumulative Effect of Adoption of Accounting Principle		-		(0.03)
	Net Income	$	0.67	$	0.47
Weighted Average Common Shares Outstanding:
	Basic	35,549,453		28,138,469
	Diluted	36,614,578		28,991,295
The accompanying notes are an integral part of the financial statements.
2

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
			March 31,		December 31,
			2004		2003
			(in thousands)
Current Assets
	Cash		$	1,083	$	1,277
	Accounts receivable			53,668		58,543
	Inventories, at average cost			20,824		31,418
	Under-recovered purchased gas costs			224		1,107
	Hedging asset - FAS No. 133			198		3,693
	Other			4,376		4,272
		Total current assets		80,373		100,310
Investments				14,032		13,840
Property, Plant and Equipment, at cost
	Gas and oil properties, using the full cost method			1,259,034		1,201,917
	Gas distribution systems			205,213		203,793
	Gas in underground storage			28,722		33,256
	Other			30,303		30,038
				1,523,272		1,469,004
	Less: Accumulated depreciation, depletion and amortization			721,977		706,720
				801,295		762,284
Other Assets				15,302		14,276
Total Assets			$	911,002	$	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 SHAREH0LDERS' EQUITY
			March 31,		December 31,
			2004		2003
			(in thousands)
Current Liabilities
	Accounts payable		$	56,598	$	54,186
	Taxes payable			6,239		5,692
	Interest payable			6,222		2,338
	Customer deposits			5,255		5,277
	Hedging liability - FAS No. 133			24,518		20,997
	Regulatory liability - hedges			-		2,137
	Other			2,489		4,441
		Total current liabilities		101,321		95,068
Long-Term Debt				255,000		278,800
Other Liabilities
	Deferred income taxes			157,499		147,295
	Other			23,044		15,859
				180,543		163,154
Commitments and Contingencies
Minority Interest in Partnership				12,525		12,127
Shareholders' Equity
	Common stock, $0.10 par value; authorized 75,000,000 shares, issued 37,225,584 shares in 2004 and 2003			3,723		3,723
	Additional paid-in capital			124,298		123,519
	Retained earnings			271,357		246,885
	Accumulated other comprehensive income (loss)			(19,517)		(12,520)
	Less:	Common stock in treasury, at cost, 1,168,196 shares at March 31, 2004 and 1,307,995 shares at December 31, 2003		(13,196)		(14,571)
		Unamortized cost of 419,585 restricted shares at March 31, 2004 and 421,617 restricted shares at December 31, 2003 issued under stock incentive plan		(5,052)		(5,475)
				361,613		341,561
Total Liabilities and Shareholders' Equity			$	911,002	$	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 three months ended
			March 31,
			2004		2003
			(in thousands)
Cash Flows From Operating Activities
	Net income		$	24,472	$	13,642
	Adjustments to reconcile net income to
	net cash provided by operating activities:
		Depreciation, depletion and amortization		16,489		13,105
		Deferred income taxes		14,372		8,887
		Ineffectiveness of cash flow hedges		979		914
		Equity in income of NOARK partnership		(192)		(1,482)
		Minority interest in partnership		399		765
		Cumulative effect of adoption of accounting principle		-		855
	Change in assets and liabilities:
		Accounts receivable		4,875		(10,523)
		Under/over-recovered gas costs		884		(1,730)
		Inventories		15,093		8,404
		Accounts payable		(2,901)		2,187
		Taxes payable		547		(1,099)
		Interest payable		3,884		3,726
		Other operating assets and liabilities		(2,161)		921
	Net cash provided by operating activities			76,740		38,572
Cash Flows From Investing Activities
	Capital expenditures			(50,551)		(30,369)
	Distribution from NOARK partnership			-		2,500
	Decrease in gas stored underground			-		4,391
	Other items			(285)		749
	Net cash used in investing activities			(50,836)		(22,729)
Cash Flows From Financing Activities
	Issuance of common stock			-		103,301
	Payments on revolving long-term debt			(151,800)		(147,500)
	Borrowings under revolving long-term debt			128,000		30,100
	Debt issuance cost			(1,428)		-
	Change in bank drafts outstanding			(2,596)		(616)
	Proceeds from exercise of common stock options			1,726		963
	Net cash used in financing activities			(26,098)		(13,752)
Increase (decrease) in cash				(194)		2,091
Cash at beginning of year				1,277		1,690
Cash at end of period			$	1,083	$	3,781
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		Loss		Total
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	-		-		-		24,472		-		-		-		24,472
Change in value of derivatives, net of tax	-		-		-		-		-		-		(6,997)		(6,997)
Total comprehensive income	-		-		-		-		-		-		-		17,475
Exercise of stock options	-		-		747		-		1,344		-		-		2,091
Issuance of restricted stock	-		-		32		-		31		(63)		-		-
Amortization of restricted stock	-		-		-		-		-		486		-		486
Balance at March 31, 2003	37,226	$	3,723	$	124,298	$	271,357	$	(13,196)	$	(45,052)	$	(19,517)	$	361,613

RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
		For the three months ended
		March 31,
			2004		2003
			(in thousands, net of tax)
Balance, beginning of period		$	(12,520)	$	(17,358)
	Current period reclassification to earnings		2,695		11,888
	Current period change in derivative instruments		(9,692)		(15,872)
Balance, end of period		$	(19,517)	$	(21,342)
The accompanying notes are an integral part of the financial statements
6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

March 31, 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 such costs (productive and nonproductive) including salaries, benefits and other internal costs directly attributable to these activities 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 t o earnings. At March 31, 2004, the Company's net book value of natural gas and oil properties did not exceed the ceiling amount. Decreases in market prices from March 31, 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.

    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 its accounting and disclosures for mineral interest use rights (leasehold acquisition costs) upon the implementation of FAS 141 and 142. However, an interpretation of FAS

7

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 $18.9 million and $16.9 million at March 31, 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 $9.4 million and $9.3 million at March 31, 2004 and December 31, 2003, respectively, that would be classified as "intangible developed leasehold" if it applied the interpretation currently being considered. 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 Emerging Issues Task Force has added this issue to its agenda and the Financial Accounting Standards Board has recently issued proposed FSP FAS 141-a and 142-a. The proposed FSP would amend FAS 141 and FAS 142 to remove some inconsistencies between the standards related to the proper classification of assets related to mineral rights. Southwestern will continue to monitor this issue and classify the use rights of mineral interests in gas and oil properties until further guidance is provided.

(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 48,000 shares, with an average exercise price of $24.78 per share at March 31, 2004, and options for 851,234 shares, with an average exercise price of $14.15 per share at March 31, 2003, were not included in the calculation of diluted shares because they would have had an antidilutive effect. The remaining 2,348,911 options at March 31, 2004, with a weighted average exercise price of $10.43, and 1,763,834 options at March 31, 2003, with a weighted average exercise price of $8.25 were included in the calculation of diluted shares. Restricted stock shares included in the calculation of diluted shares were 171,638 and 498,664 at March 31, 2004 and 2003, respectively.

8

(5)        DEBT

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

	March 31,		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 (2.34% at March 31, 2004 and 2.67% at December 31, 2003) unsecured revolving credit arrangements		30,000		53,800
Total debt	$	255,000	$	278,800

    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 March 31, 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 March 31, 2004, the Company's net liability related to its cash flow hedges was $31.7 million. Additionally, at March 31, 2004, the Company had recorded a net of tax cumulative loss to other comprehensive income (equity section of the balance sheet) of $19.0 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. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the adoption of FAS 133.

9

(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.

	Exploration
	and			Gas
	Production			Distribution		Marketing		Other			Total
	(in thousands)
Three months ended March 31, 2004:
Revenues from external customers	$	49,245		$	61,203	$	9,186	$	156		$	119,790
Intersegment revenues		9,826			56		52,074		112			62,068
Operating income		33,429			8,810		887		181			43,307
Depreciation, depletion and amortization expense		13,892			1,601		9		24			15,526
Interest expense(1)		2,906			1,172		63		244			4,385
Provision for income taxes(1)		11,152			2,869		305		46			14,372
Assets		697,470			159,341		17,531		36,660	(2)		911,002	(2)
Capital expenditures		56,583	(3)		1,939		--		115			58,637	(3)

Three months ended March 31, 2003:
Revenues from external customers	$	28,609	$	57,440	$	12,606	$	--		$	98,655
Intersegment revenues		11,127		67		35,314		112			46,620
Operating income		18,937		8,005		691		41			27,674
Depreciation, depletion and amortization expense		10,814		1,534		12		23			12,383
Interest expense(1)		3,723		981		--		243			4,947
Provision for income taxes(1)		5,496		2,640		263		488			8,887
Assets		545,682		155,166		18,320		40,545	(2)		759,713	(2)
Capital expenditures		28,448		1,841		--		80			30,369

(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 $8.1 million of accrued expenditures.

10

    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 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.

(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.

	For the three months ended
	March 31,
	2004		2003
	(in thousands)
Interest payments		$379		$968
Income tax payments		$   --		$  --

 (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 March 31, 2004 and December 31, 2003, the principal outstanding for these notes was $69.0 million. 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 which is 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. This contract expires in 2014.

11

    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 three months ended
	March 31,
	2004		2003
	(in thousands, except per share)
Net income, as reported	$	24,472	$	13,642
Add back: Amortization of restricted stock		306		434
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(597)		(715)
Pro forma net income	$	24,181	$	13,361
Earnings per share:
Basic-as reported		$0.69		$0.48
Basic-pro forma		0.68		0.47
Diluted-as reported		0.67		0.47
Diluted-pro forma		0.66		0.46

    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

12

years for all option grants. There were 7,000 options granted in the first three months of 2004 and no options granted in the first three 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 first quarters of 2004 and 2003:

		Pension Benefits			Postretirement Benefits
	2004		2003		2004		2003
Service cost	$	601	$	543	$	43	$	35
Interest cost		923		915		63		59
Expected return on plan assets		(1,136)		(902)		(10)		(9)
Amortization of prior service cost		111		111		--		--
Amortization of net (gain) loss		58		166		22		22
Amortization of transition obligation		--		--		25		22
Net periodic benefit cost	$	557	$	833	$	143	$	129

    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 March 31, 2004, $0.2 million of contributions have been made.

13

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-month period ended March 31, 2004, and the comparable period 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.

    We reported net income of $24.5 million, or $0.67 per share on a diluted basis, on revenues of $119.8 million for the three months ended March 31, 2004, compared to $13.6 million, or $0.47 per share, on revenues of $98.7 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 Exploration and Production, or E&P segment. Operating income for our E&P segment was $33.4 million for the quarter ended March 31, 2004, up from $18.9 million for the same period in 2003. Operating income for our gas distribution segment was $8.8 million for the quarter ended March 31, 2004, compared to $8.0 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 $76.7 million for the three months ended March 31, 2004 , compared to $38.6 million for the same period in 2003.

    In the first quarter of 2004, our gas and oil production continued to increase, reaching 11.4 Bcfe, up from 8.9 Bcfe in the first quarter of 2003 and 11.2 Bcfe in the fourth quarter 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.

    Our capital investments totaled $58.6 million for the first quarter of 2004, up from $30.4 million in the first quarter of 2003. We invested $56.6 million in our E&P segment in the first three months

14

of 2004, compared to $28.4 million for the same period in 2003. Capital investments currently planned for calendar year 2004 total $203.5 million, including $194.0 million for our E&P segment.

    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 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.

RESULTS OF OPERATIONS

Exploration and Production

	For the three months
	ended March 31,
	2004		2003
Revenues (in thousands)	$	59,071	$	39,736
Operating income (in thousands)	$	33,429	$	18,937
Gas production (MMcf)		10,516		8,101
Oil production (MBbls)		152		125
Total production (MMcfe)		11,428		8,851
Average gas price per Mcf, including hedges	$	4.92	$	4.15
Average gas price per Mcf, excluding hedges	$	5.34	$	6.41
Average oil price per Bbl, including hedges	$	28.43	$	27.69
Average oil price per Bbl, excluding hedges	$	33.88	$	32.06
Average unit costs per Mcfe
Lease operating expenses	$	0.38	$	0.42
General & administrative expenses	$	0.39	$	0.44
Taxes, other than income taxes	$	0.26	$	0.27
Full cost pool amortization	$	1.18	$	1.18

Revenues, Operating Income and Production

    Revenues. Revenues for our E&P segment were up 49% to $59.1 million for the three-month period ended March 31, 2004, compared to $39.7 million for the same period in 2003. The increase was primarily due to increased production volumes and higher gas and oil prices realized for our production.

15

    Operating Income. Operating income for the E&P segment was up 77% to $33.4 million for the three months ended March 31, 2004, compared to $18.9 million for the same period 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 first quarter of 2004 was 11.4 billion cubic feet (Bcf) equivalent, up 29% from 8.9 Bcf equivalent in the first quarter of 2003. The comparative increase in first quarter production in 2004 primarily resulted from an increase in production from the Overton Field in East Texas due to the accelerated development of the field. Gas production was 10.5 Bcf for the first quarter of 2004 compared to 8.1 Bcf for the first quarter of 2003. Intersegment sales to our gas distribution systems were 1.7 Bcf during the three months ended March 31, 2004, compared to 1.7 Bcf for the same period in 2003. Our oil production was 152 thousand barrels (MBbls) during the first quarter of 2004, up from 125 MBbls for the same period of 2003.

Commodity Prices

    The average price realized for our gas production, including the effect of hedges, was $4.92 per thousand cubic feet (Mcf) for the three months ended March 31, 2004, up from $4.15 per Mcf 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 quarter of 2004 by $0.42 per Mcf, and by $2.26 per Mcf during the same period of 2003.  Additionally, we have historically received demand charges related to sales made to our utility segment, which has 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 25.1 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 $28.43 per barrel for our oil production, including the effect of hedges, during the three months ended March 31, 2004, up from $27.69 per barrel for the same period of 2003. The average price we received for our oil production in the first quarter of 2004 and 2003 was reduced by $5.45 per barrel and $4.37 per barrel, respectively, due to the effects of our hedging activities. For the remainder of 2004, we have hedged 315,000 barrels of our oil production at an average NYMEX price of $28.21 per barrel.

Operating Costs and Expenses

    Lease operating expenses per Mcfe for this business segment were $0.38 for the first quarter of 2004, compared to $0.42 for the same period in 2003. Lease operating expenses per unit decreased in 2004 as a larger portion of our production is being provided from the Overton Field which has lower per unit operating costs. Taxes other than income taxes per Mcfe were $0.26 for the first

16

 quarter of 2004, compared to $0.27 for the same period in 2003. Severance taxes per Mcfe decreased during the quarter primarily due to comparatively lower average market prices in effect for natural gas, as reflected in the average price received for our production excluding the effect of hedges. General and administrative expenses per Mcfe were $0.39 during the first quarter of 2004, down from $0.44 for the same period in 2003. The decrease in per unit general and administrative expenses in 2004 is primarily due to the increase in our production.

    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. 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 impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserv es. At March 31, 2004, our unamortized costs of gas and oil properties did not exceed this ceiling amount. Our standardized measure at March 31, 2004 was calculated based upon quoted market prices of $5.42 per Mcf for gas and $35.76 per barrel for oil, adjusted for market differentials. A decline in gas and oil prices from the March 31, 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 ended
	March 31,
	2004		2003
Revenues (in thousands)	$	61,259	$	57,507
Gas purchases (in thousands)	$	41,348	$	38,167
Operating costs and expenses (in thousands)	$	11,101	$	11,335
Operating income (in thousands)	$	8,810	$	8,005
Deliveries (Bcf)
Sales and end-use transportation		9.8		10.7
Off-system transportation		1.0		--
Customers at quarter-end		143,347		140,688
Average sales rate per Mcf	$	8.11	$	6.77
Heating weather - degree days		2,061		2,275
Percent of normal		96%		106%

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-month period ended March 31, 2004 increased 7% from the comparable period 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. Operating income of our gas distribution segment increased $0.8 million in the first quarter of 2004, as compared to the same period of 2003. The increase was 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 caused by warmer than normal weather. Weather during the first three months of 2004 was 4% warmer than normal and 10% warmer than the same period of 2003.

Deliveries and Rates

    The utility systems delivered 9.8 Bcf to sales and end-use transportation customers during the three-month period ended March 31, 2004, compared to 10.7 Bcf for the same period in 2003. The decrease in deliveries during the first three months of 2004 was primarily due to the effects of warmer weather and customer conservation brought about by high gas prices in recent years. 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 three months of 2004 was reflected in the utility segment's average rate for its sales which increased to $8.11 per Mcf, up from $6.77 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 adjustment c lauses. Our utility segment hedged 3.8 Bcf of gas purchases in the first three months of 2004 which had the effect of decreasing its total gas supply cost by $0.1 million. In the first three months 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 quarter ended March 31, 2004 were lower than the comparable periods of the prior year due primarily to decreased general and administrative expenses. The decrease in general and administrative expense primarily resulted from decreased pension costs.

18

Marketing and Transportation

Marketing

	For the three months ended
	March 31,
	2004		2003
Revenues (in thousands)	$	61,260	$	47,920
Operating income (in thousands)	$	887	$	691
Gas volumes marketed (Bcf)		12.3		8.5

    Our operating income from natural gas marketing was $0.9 million on revenues of $61.3 in the first quarter of 2004 compared to $0.7 million on revenues of $47.9 in the same period in 2003. The increase in revenues for the three-month period ended March 31, 2004, as compared to the same period in the prior year, was due to an increase in affiliated volumes marketed and an increase in natural gas commodity prices. These increases were largely offset by comparable increases in purchased gas costs. We marketed 10.1 Bcf of affiliated gas in the first quarter of 2004, representing 82% of total volumes marketed, compared to 5.7 Bcf, or 67% of total volumes marketed, 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, "Quantitative and Qualitative Disclosure About Market Risk" in this Form 10-Q for additional information.

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 first three months of 2004, compared to pre-tax income of $1.5 million for the same period in 2003. These amounts are recorded in other income (expense) in our income statement. The pre-tax income in the first three 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 quarters 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.

Interest Expense

    Interest costs, net of capitalization, decreased 11% in the first quarter of 2004, compared to the same period in 2003, due to lower average borrowings and increased capitalized interest. Our average borrowings decreased during the first 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.

19

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 costs excluded from amortization in our E&P segment.

Income Taxes

    The effective tax rate for the three months ended March 31, 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 first quarter of 2004 compared to pension expense of $0.8 million for the same period 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 March 31, 2004, $0.2 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 March 31, 2004, we had $30.0 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") which are expected to exceed the net cash generated by our operations. 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 $76.7 million in the first three months of 2004, compared to $38.6 million for the same period of 2003. The primary components of cash generated from operations are net income, depreciation, depletion and amortization, the provision for deferred income taxes and changes in operating assets and liabilities. Cash from operating activities increased in the first quarter of 2004, as compared to the first quarter of 2003, due primarily to increased net income and the related increase in deferred income taxes and changes in our operating assets and liabilities. For the first three months of 2004 and 2003, cash provided by operating activities provided over 100% of our cash requirements for capital expenditures.

20

    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 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 three months of 2004 were $58.6 million, including $8.1 million of accrued expenditures, compared to $30.4 million for the same period in 2003. We currently expect our capital investments for calendar year 2004 to be approximately $203.5 million. Our 2004 capital investment program is expected to be funded through cash flow from operations and 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 March 31, 2004, the outstanding principal amount of these notes was $69.0 million and our share of the guarantee was $41.4 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 three months of 2004 and 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 (expense) income related to our NOARK investment was pre-tax income of $0.2 million for the first three month of 2004, compared to pre-tax income of $1.5 million for the same period in 2003. Our share of the pre-tax income in the first three months 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.

21

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 March 31, 2004 are as follows:

Contractual Obligations

	Payments Due by Period
			Less than		1 to 3		3 to 5		More than
	Total		1 Year		Years		Years		5 Years
	(in thousands)
Long-term debt	$	255,000	$	--	$	155,000	$	--	$	100,000
Operating leases(1)		5,820		1,228		1,991		904		1,698
Unconditional purchase obligations(2)		--		--		--		--		--
Demand charges(3)		73,654		9,826		17,200		14,370		32,258
Other obligations(4)		4,802		4,647		155		--		--
	$	339,276	$	15,701	$	174,346	$	15,274	$	133,956

(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 March 31, 2004 totaled 1.7 Bcf, comprised of 0.9 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 $67.6 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 $6.1 million of demand transportation charges.
(4)	Our significant other contractual obligations include approximately $2.1 million for funding of benefit plans, approximately $0.4 million of land leases, approximately $1.0 million for drilling rig commitments and approximately $1.0 million of various information technology support and data subscription agreements.

    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 $0.6 million has been recorded in the first three months 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.

22

    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 March 31, 2004 the principal outstanding for these notes was $69.0 million and our share of the guarantee was $41.4 million. The notes require semi-annual principal payments of $1.0 million.

    Our utility segment is in the process of finalizing a new firm transportation agreement which would result in an additional demand charge commitment totaling approximately $34 million over its ten-year term.

Financing Requirements

    Our total debt outstanding was $255.0 million at March 31, 2004 and $278.8 million at December 31, 2003. Of the total outstanding at March 31, 2004, $30.0 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. We 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 facilities.

    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 March 31, 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 pric es for natural gas and oil.

    At March 31, 2004 our capital structure consisted of 41% debt (excluding our several guarantee of NOARK's obligations), down from 45% debt at December 31, 2003, and our ratio of EBITDA to interest expense was 10.3. At March 31, 2004, the NOARK partnership had outstanding debt totaling $69.0 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%.

    During the first quarter of 2003, our total debt decreased by $80.4 million primarily due to the initial use of the net proceeds from the issuance of common stock to pay off the balance of our revolving debt. We are reborrowing the repaid amounts as necessary to fund the acceleration of the development drilling of our Overton Field properties in East Texas and for general corporate purposes as these costs are incurred.

23

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 $20.9 million at March 31, 2004, compared to negative working capital of $5.2 million at December 31, 2003. Current assets decreased by 20% in the first three months of 2004 while current liabilities increased 7%. The decrease in current assets during the first three months of 2004 was due primarily to a $10.6 million decrease in current inventories that resulted from a $12.3 million decrease in current gas stored underground for gas sold during the first quarter. The change in current liabilities was primarily caused by an increase in our hedging liability and interest payable. Under-recovered purchased gas costs for the Company's gas distribution segment were $0.2 million at March 31, 2004, compared to $1.1 million at December 31, 2003. Purchased gas costs are recovered from our utility customers in subsequent mo nths through automatic cost of gas adjustment clauses included in the utility's filed rate tariffs. Changes in other current assets and current liabilities are primarily due to the timing of expenditures and receipts. At March 31, 2004, we had a current hedging liability of $24.5 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) 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 plus the lower of cost or market value of unproved properties. If the net capitalized costs of natural gas and oil properties exceed the ceiling, 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 March 31, 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.

24

    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 full cost m ethod 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 March 31, 2004 and December 31, 2003, the Company had undeveloped leasehold of approximately $18.9 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 $9.4 million and $9.3 million at March 31, 2004 and December 31, 2003, respectively, that would be classified as "intangible developed leasehold" if it applied the interpretation currently being considered. 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 Emerging Issues Task Force has added this issue to its agenda and the Financial Accounting Standards Board has recently issued proposed FSP FAS 141-a and 142-a. The proposed FSP would amend FAS 141 and FAS 142 to remove some inconsistencies between the standards related to the proper classification of assets related to mineral rights. Southwestern will continue to monitor this issue and classify the use rights of mineral interests in gas and oil properties until further guidance is provided.

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

25

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 Q ualitative 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

26

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 $0.6 million was recorded in the first quarter 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 7.9 Bcf at $2.98 at March 31, 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 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.

27

    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 in our 2003 Annual Report on Form 10-K which is 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

28

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 incorporated by reference 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.

29

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 March 31, 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.

30

    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 March 31, 2004, the fair value of these financial instruments was a $31.7 million liability.

	Expected Maturity Date
	2004		2005
Production and Marketing
Natural Gas
Swaps with a fixed price receipt
Contract Volume (Bcf)		5.4	11.0
Weighted average price per Mcf		$3.96	$4.87
Fair value (in millions)		($10.8)	($6.1)
Price collars
Contract volume (Bcf)		19.5	18.0
Weighted average floor price per Mcf		$3.92	$4.50
Fair value of floor (in millions)		$0.3	$3.3
Weighted average ceiling price per Mcf		$6.51	$6.94
Fair value of ceiling (in millions)		($10.8)	($5.9)
Swaps with a fixed price payment
Contract volume (Bcf)		0.2	-
Weighted average price per Mcf		$5.06	-
Fair value (in millions)		$0.2	-
Oil
Swaps with a fixed price receipt
Contract volume (MBbls)		0.3	0.2
Weighted average price per Bbl		$28.21	$30.05
Fair value (in millions)		($1.7)	($0.2)
Natural Gas Purchases
Swaps with a fixed price payment
Contract volume (Bcf)		-	-
Weighted average price per Mcf		-	-
Fair value (in millions)		-	-

31

    At March 31, 2004, the Company had outstanding fixed-price basis differential swaps on 3.0 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 March 31, 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 March 31, 2004 and prior to April 26, 2004, we entered into additional derivative contracts to hedge gas production sales. Costless collar hedges on 1.0 Bcf of 2005 gas production sales have an average floor of $4.75 per Mcf and an average ceiling of $8.08 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 significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of our evaluation.

32

PART II

OTHER INFORMATION

Items 1 - 5.

No developments required to be reported under Items 1 - 5 occurred during the quarter ended March 31, 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

	Item	Financial Statements
Date of Report	Number	Required to be Filed
April 20, 2004	9	No
March 25, 2004	9	No
March 9, 2004	9	No
March 3, 2004	9	No

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

33

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.) [Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986]
		(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:	April 29, 2004	/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.) [Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986]
		(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:	April  29, 2004	/s/ GREG D. KERLEY
			Greg D. Kerley
			Chief Financial Officer

EX-32

Exhibit 32

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 March 31, 2004 (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:	April 29, 2004	/s/ HAROLD M. KORELL
			Harold M. Korell
			Chief Executive Officer
Dated:	April 29, 2004	/s/ GREG D. KERLEY
			Greg D. Kerley
			Chief Financial Officer