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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(X) Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2002

Commission file number 1-8246

Southwestern Energy Company
(Exact name of Registrant as specified in its charter)

2350 North Sam Houston Parkway East, Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)

(281) 618-4700
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   x      No  o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes   x      No  o

     The number of shares outstanding as of February 13, 2003, of the Registrant’s Common Stock, par value $0.10, was 25,980,378. The aggregate market value of the voting stock held by non-affiliates of the Registrant was $289,713,706 based on the New York Stock Exchange – Composite Transactions closing price on February 13, 2003, of $11.40. For purposes of this calculation, the Registrant has assumed that its directors and executive officers are affiliates.

     Document incorporated by reference: Portions of the Registrant’s Definitive Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 14, 2003 are incorporated by reference into Part III of this Form 10-K.

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SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
for fiscal year ended December 31, 2002

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EXHIBIT INDEX

     This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. We refer you to “Risk Factors” in Item 1 of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II of this Form 10-K for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements.

     The electronic version of this Annual Report on Form 10-K, along with other information about us and our operations, financial information, other documents filed with the Securities and Exchange Commission, or the SEC, and other useful information about us can found on our website at http://www.swn.com.

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PART I

ITEM 1. BUSINESS

Overview

     Southwestern Energy Company is an independent energy company primarily focused on the exploration for and production of natural gas. We were originally organized in 1929 in Arkansas as a local gas distribution company. Today, we are an exempt holding company under the Public Utility Holding Company Act of 1935, conduct our primary activities through four wholly-owned subsidiaries and derive the vast majority of our operating income and cash flow from our natural gas and oil exploration and production, or E&P, business. In February 2001, we relocated our corporate headquarters from Fayetteville, Arkansas to Houston, Texas. All of our operations are located within the United States. We operate principally in three segments:

	1.		Exploration and Production – Our primary business is natural gas and crude oil exploration, development and production, with our operations principally located in Arkansas, Oklahoma, Texas, New Mexico and Louisiana. We engage in natural gas and oil exploration and production through our wholly-owned subsidiaries, SEECO, Inc., Southwestern Energy Production Company, (which we refer to as SEPCO), and Diamond “M” Production Company. SEECO operates exclusively in Arkansas, holds a large base of both developed and undeveloped gas reserves and conducts an ongoing drilling program in the historically productive Arkansas part of the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Oklahoma portion of the Arkoma Basin, the Permian Basin of Texas and New Mexico, and in Louisiana and East Texas. Diamond “M” operates properties in the Permian Basin of Texas. A wholly-owned subsidiary of SEPCO, Overton Partners, L.L.C., owns an interest in Overton Partners, L.P., a limited partnership formed in 2001 to drill and complete 14 development wells in SEPCO’s Overton Field properties in East Texas.
	2.		Natural Gas Distribution – We are also engaged in the gathering, distribution and transmission of natural gas. Our wholly-owned subsidiary Arkansas Western Gas Company, which we refer to as Arkansas Western, operates integrated natural gas distribution systems in northern Arkansas serving approximately 140,000 retail customers. Arkansas Western is the largest single purchaser of SEECO’s gas production.
	3.		Marketing, Transportation and Other – As a complement to our other businesses, we provide marketing and transportation services in our core areas of operation. Our gas marketing subsidiary, Southwestern Energy Services Company, was formed in 1996 to better enable us to capture downstream opportunities which arise through marketing and transportation activity. We also hold a 25% general partnership interest in the NOARK Limited Partnership, which we refer to as NOARK, which owns the Ozark Pipeline, a 749-mile interstate pipeline with a total throughput capacity of 330 MMcf per day, along with related gathering systems. We also own an interest in approximately 150 acres of real estate, most of which is undeveloped and located in Fayetteville, Arkansas.

Our Business Strategy

     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 added for each dollar invested, which we refer to as PVI. The PVI of the future expected cash flows for each project is determined using a 10% discount rate. We target adding $1.30 to $1.50 of discounted pre-tax PVI for each dollar we invest. For example, the average economics for the wells we drilled at the Overton Field in 2002, based on current expected costs and production and assuming an average NYMEX price of $4.00 per Mcf of gas and $25.00 per barrel of oil, would result in an estimated discounted pre-tax PVI of $1.90 for every dollar invested. This would result in an approximate pre-tax rate of return of 35%. We are also focused on creating and capturing additional value beyond the wellhead through our natural gas distribution, marketing and transportation businesses.

     For our E&P business, the key elements of our business strategy are:

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•		Continue to Exploit and Develop Existing Asset Base. We seek to maximize the value of our existing asset base by developing and exploiting our properties that have substantial production and reserve growth potential while also controlling per unit production costs. We intend to add proved reserves and increase production through the use of advanced technologies, including detailed technical analysis of our properties, and by drilling infill locations and selectively recompleting existing wells. We also plan to drill step-out wells to expand known field limits.
•		Grow Through Exploration. We conduct an active exploration program that is designed to complement our lower risk exploitation and development drilling efforts with moderate to high risk exploration projects that have greater reserve potential. We employ a rigorous prospect selection process utilizing state-of-the-art computer-aided exploration technology to analyze and interpret geological and geophysical data, including a large inventory of 3-D seismic data. We intend to manage our exploration expenditures through the optimal scheduling of our drilling program and by selectively reducing our participation in certain exploratory prospects through promoted sales of interests to industry partners.
•		Rationalize Our Property Portfolio. We actively pursue opportunities to reduce production costs of our properties. We continually seek to rationalize our portfolio of E&P assets by selling marginal properties in an effort to reduce production costs and improve overall return.
•		Pursue Strategic Acquisitions. We selectively review opportunities to acquire producing properties and leasehold acreage, focusing in particular on the regions where we have existing operations. In addition, we seek to acquire operational control of properties that we believe have significant exploration and exploitation potential.

Recent Development

     Sale of Our Mid-Continent Properties. In November 2002, we sold our remaining non-strategic Mid-Continent properties, including our properties in the Sho-Vel-Tum area in southern Oklahoma, the Anadarko Basin in western Oklahoma and the Sooner Trend in northwestern Oklahoma, for a total of $26.4 million. These properties represented approximately 32.9 Bcfe of reserves and produced approximately 2.5 Bcfe annually. We expect this divestiture to result in a decrease in our future average production costs per unit of production. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Exploration and Production — Operating Costs and Expenses.”

Exploration and Production

     In 1943, we commenced a program of exploration for and development of natural gas reserves in Arkansas for supply to our utility customers. In 1971, we initiated an E&P program outside Arkansas, unrelated to the utility’s requirements. Since that time, our E&P activities outside Arkansas have expanded substantially. In 1998, we brought in a new executive management team for our E&P business which has implemented a number of initiatives to refocus our E&P business. These efforts have included a recruiting campaign to improve our technical professional staff which has resulted in a change in that staff of more than 75%. Our explorationists now have an average of over 20 years of experience and have a proven track record of finding natural gas and oil during their careers. The operations of our E&P business were reorganized into asset management teams based on the geographic location of our exploration and development projects. In addition, a new incentive compensation plan, which includes stock based awards, was established to more closely align our employees efforts with the interests of our shareholders.

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Areas of Operation

     We operate our E&P business in four regions—Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast. Operating income for our E&P business was $36.0 million and EBITDA was $83.1 million in 2002. Our operating income and EBITDA declined in 2002 from $69.3 million and $115.0 million, respectively, in 2001, primarily because lower realized natural gas and oil prices decreased our revenues while our operating expenses slightly increased. We refer you to “Business—Other Items—Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our operating income as derived from our audited financial information.

     As of December 31, 2002, our estimated proved natural gas and oil reserves were 415.3 Bcfe and had a pre-tax PV-10 value of $694.1 million. Approximately 90% of our proved reserves were natural gas and 77% were classified as proved developed. We operate approximately 74% of our reserves, based on our pre-tax PV-10 value, and our average proved reserves-to-production ratio, or average reserve life, approximated 10.4 years at year-end 2002. Revenues of our E&P subsidiaries are predominantly generated from production of natural gas. Sales of natural gas production accounted for 88% of total operating revenues for this segment in 2002, 89% in 2001, and 82% in 2000.

     In 2002, we replaced 209% of our production volumes by adding an estimated 83.7 Bcfe of proved natural gas and oil reserves at a finding and development cost of $1.02 per Mcfe, excluding reserve revisions. Our finding and development cost including the effect of upward reserve revisions due to higher year-end commodity prices was $0.99 per Mcfe in 2002. For the three years ended December 31, 2002, we achieved an average reserve replacement ratio of 210% and an average finding and development cost of $1.04 per Mcfe, excluding reserve revisions. Including reserve revisions, these three-year averages were 193% and $1.13 per Mcfe, respectively.

     Our portfolio includes low-risk development drilling in the Arkoma Basin and East Texas, moderate-risk exploration and exploitation properties in the Permian Basin, and higher risk, greater-potential exploration opportunities in the onshore Gulf Coast region. The following table provides information as of December 31, 2002 related to proved reserves, well count, and net acreage, and 2002 annual information as to production and capital expenditures, for each of our core operating areas and overall:

			Arkoma				East Texas				Permian				Gulf Coast				Total
Estimated Proved Reserves:
Total Reserves (Bcfe)				188.7				111.0				57.1				58.5				415.3
	Percent of Total			45%				27%				14%				14%				100%
	Percent Natural Gas			100%				95%				52%				86%				90%
	Percent Proved Developed			84%				65%				83%				74%				77%
Production (Bcfe)				19.8				5.9				6.9	(1)			7.5				40.1
Capital Expenditures (millions)				$18.2				$33.6				$5.4				$28.0				$85.2
Total Gross Wells				813				49				386				79				1,327
Total Net Acreage				263,112				16,117				39,425				82,770				401,424
	Net Undeveloped Acreage			99,341				5,529				22,391				57,962				185,223
Pre-tax PV-10:
	Amount (millions)		$	329.1			$	151.9			$	90.2			$	122.9			$	694.1
	Percent of Total			47%				22%				13%				18%				100%
	Percent Operated			79%				96%				38%				54%				74%

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     Arkoma Basin. The Arkoma Basin provides a solid foundation for our E&P program and represents a significant source of our production and reserves. At December 31, 2002, we had approximately 188.7 Bcf of natural gas reserves in the Arkoma Basin, representing approximately 45% of our total reserves. During 2002, we participated in 25 wells and 41 workovers which added 18.3 Bcf of gas reserves at a finding and development cost of $0.99 per Mcf. Our gas production in the Arkoma Basin was 19.8 Bcf during 2002, or 54.2 MMcf per day.

     Our activities in the Arkoma Basin continue to generate a significant amount of our cash flow. With three-year average finding and development costs of $1.08 per Mcf and three-year average production, or lifting, costs of $0.30 per Mcf (including production taxes), our cash margins in the Arkoma Basin are very attractive. Lifting costs continued to be low during 2002 at $0.36 per Mcf (including production taxes). Including the impact of commodity hedges, we realized 83% of the average price we received for natural gas from the Arkoma Basin, after direct general and administrative expenses and cash expenses.

     We have traditionally operated in a portion of the Arkoma Basin that is primarily within the boundaries of our utility gathering system in Arkansas which we refer to as the “fairway.” Our strategy in the fairway is to delineate new geologic prospects and extend previously identified trends using our extensive database of regional structural and stratigraphic maps. In 2002, we completed 8 wells out of 11 drilled in the fairway and those wells added 3.9 Bcf of new natural gas reserves. An especially encouraging prospect among the fairway wells is the Grimmer #1-17 well, which is located in Johnson County, Arkansas and, as of April 2002, tested at a rate of 10.7 MMcf per day from Hale perforations at 4,100 feet. Our average working interest in the 2002 fairway wells is 67% and our average net revenue interest is 58%. We intend to drill up to 15 wells in the fairway portion of the Arkoma Basin in 2003.

     In recent years, we have extended our development program into the Oklahoma portion of the Arkoma Basin, and have also tested new exploration plays to continue its growth. In 2002, we continued the development of our Ranger Anticline prospect area, located at the southern edge of the Arkansas portion of the basin. An example of our continued successful development of this complex overthrust play is the Brasher #1-11 well that was drilled and put into production in August 2002 at a rate of 12.0 MMcf per day from Lower Borum sands at approximately 5,500 feet and 6,750 feet. We have begun testing new exploration prospect areas on the southern edge of the Arkoma Basin similar to our Ranger Anticline play.

     Additionally in 2002, we accelerated our extensive workover program in the Arkoma Basin which includes fracture stimulations, artificial lift, recompletion and wellbore repair projects, and this acceleration has provided meaningful production increases. We performed 41 of these workover projects in 2002, resulting in net production increases totaling 6.9 MMcf per day at a total net cost of $3.9 million. One workover project, the Currier #1-35 well in Franklin County, Arkansas, was recompleted to the Sells zone and stimulated in the Casey sand. This work increased gross production from the well by 850 Mcf per day and resulted in a net reserve addition of 1.1 Bcf.

     Our strategy for the Arkoma Basin is to continue our development drilling and workover programs at a level that maintains our production and reserve base. In 2003, we plan to invest approximately $22.6 million in the Arkoma Basin to drill approximately 30 wells and perform approximately 60 workover projects. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures” for a discussion of our planned capital expenditures for 2003.

     East Texas. The Overton Field in Smith County, Texas provides us with a low-risk, multi-year drilling program with significant production and reserve growth potential based on the level of infill drilling that is possible in the field over the next several years. Our interest in the Overton Field (which now totals approximately 16,500 gross acres) was originally acquired in April 2000 and was primarily developed on 640-acre spacing, or one well per square mile. Analogous Cotton Valley fields in the area have been drilled to 80-acre spacing, and in some cases to 40-acre spacing. We expect to receive regulatory approval to allow downspacing of our properties in the Overton Field to 80-acre spacing, which will provide us with an extensive inventory of additional drilling locations. Our average working interest in the Overton Field is 97% and our average net revenue interest is 79%.

     We expanded our position in the area during 2001 through a farm-in of approximately 5,800 adjacent acres. This acreage, which we call “South Overton,” contains nine 640-acre units, most of which have only been drilled to 320-acre spacing. The farm-in agreement requires us to drill a minimum of one well per 120 days on this acreage in 2003. Our current net revenue interest in South Overton is 73%.

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     In 2001, SEPCO formed a limited partnership with an investor to drill and complete 14 development wells in the Overton Field. All 14 development wells have been completed and we have no continuing obligations to drill additional wells. Because SEPCO is the sole general partner and owns a majority interest in the partnership, operating and financial results for the partnership are consolidated with our other operations and the investor’s share of the partnership activity is reported as a minority interest item in the financial statements. During 2002 and 2001, the minority interest owner in the partnership contributed $0.5 million and $13.5 million, respectively, in capital to the limited partnership. The investor’s share of 2002 and 2001 revenues, less operating costs and expenses, was $1.5 million and $0.9 million, respectively.

     We continue to pursue potential acquisitions in the Overton Field area and during 2002 we acquired 3,300 net acres of land offsetting recent Travis Peak and Cotton Valley development in Anderson County, Texas. While undeveloped at this time, we see the potential to apply technologies we refined in the Overton Field to this acreage block, which is located approximately 55 miles southwest of the Overton Field.

     In 2002, we drilled a total of 15 wells at the Overton Field and three wells at South Overton. All 18 wells were successful. To date, we have drilled a total of 33 wells in the area with a 100% success rate. Daily gross production at the Overton Field has increased from 2.0 MMcfe in March 2001 to approximately 27.0 MMcfe at year-end 2002 resulting in net production of 5.9 Bcfe during 2002. Our average production costs (including production taxes) decreased to $0.40 per Mcfe in 2002 from $0.70 per Mcfe in 2001, and that unit rate could decline further as production from the field increases.

     Our proved reserves at the Overton Field increased to 111.0 Bcfe at year-end 2002, or 27% of our total reserves. We invested approximately $33.6 million at the Overton Field during 2002 which resulted in proved reserve additions of 56.4 Bcfe with a finding and development cost of $0.60 per Mcfe compared to a finding and development cost of $0.82 per Mcfe at the Overton Field in 2001.

     Continued downspacing should allow us to drill an additional 100 wells in the area over the next two years. This should achieve 80-acre spacing in the majority of the higher potential areas. Our results at the Overton Field over the past two years have been significant and we believe that the acceleration of the field’s development will provide substantial growth in production and reserves over the next few years. We intend to invest approximately $78.0 million in East Texas during 2003, which includes drilling up to 47 new wells using four rigs at the Overton Field. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures” for a discussion of our planned capital expenditures in 2003.

     Permian Basin. At December 31, 2002, our proved reserves in the Permian Basin were 57.1 Bcfe, or 14% of our total reserves. Our production in the basin during 2002 was 4.9 Bcfe, or 13.4 MMcfe per day, and our production costs (including production taxes) averaged $1.13 per Mcfe. During 2002, our capital expenditures totaled $5.0 million, resulting in reserve additions of 1.4 Bcfe. Excluding reserve revisions, our three-year average finding and development cost in the basin was $2.23 per Mcfe and three-year average reserve replacement ratio was 85% for the period ended December 31, 2002.

     While our overall results in the basin were disappointing in 2002, we have recently experienced some encouraging results from drilling horizontal wells targeting the Cherry Canyon sand formation. The Peregrine #1 well located in Eddy County, New Mexico, was drilled and completed in 2002 in the Cherry Canyon horizon at 4,850 feet, with a 1,390-foot horizontal lateral. We estimate that the well exposed 720 feet of well-developed pay. We operate this well with a 100% working interest. This well is currently producing approximately 90 barrels of oil per day and we expect to drill up to three more horizontal wells in this area in 2003.

     We de-emphasized our drilling activities in the Permian Basin in 2002 and will continue to do so in 2003. In 2003, we plan to invest approximately $4.8 million in the Permian Basin, to drill up to nine wells. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Expenditures” for a discussion of our planned capital expenditures in 2003.

     Gulf Coast. Our Gulf Coast operations are located in the onshore areas of Texas and Louisiana. Our proved reserves in these areas totaled 58.5 Bcfe at December 31, 2002, or 14% of our total revenues. Approximately 29.8 Bcfe of our proved reserves in the Gulf Coast was located in Louisiana. Average net daily production in the Gulf Coast area was 20.5 MMcfe and production costs (including production taxes) averaged $1.07 per Mcfe during 2002. We invested $28.0 million in the area in 2002 and added 7.6 Bcfe of proved reserves. Of the $28.0 million in capital investments, approximately $5.8 million was invested in leasehold and seismic for future prospect development. Excluding reserve revisions, our three-year average finding and development cost in the Gulf Coast region was $1.83 per Mcfe and three-year reserve replacement ratio was 246% for the period ending December 31, 2002. Including revisions, these three-year averages were $2.13 per Mcfe and 212%.

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     South Louisiana continues to be the main focus area of our exploration activities in the Gulf Coast. Since our first discovery in December 1999, the efforts of our exploration program have resulted in eight successful wells out of the last 18 drilled in South Louisiana. In 2002, we participated in eight wells, of which two were successful. During 2002, we were also active in acquiring seismic data to facilitate future exploration in the area. We completed our 135-square mile Duck Lake 3-D seismic project located in St. Martin and St. Mary Parishes and are currently interpreting that data for prospects to be drilled later in 2003 and beyond. We are the operator of this project, and hold a 50% working interest. Additionally, we completed a transaction late in 2002 with a major seismic data vendor for a license to approximately 1,033 square miles of 3-D seismic data in other prospective areas in the southern half of Louisiana. Our current 3-D database in South Louisiana now includes over 2,700 square miles, has the potential to generate a significant inventory of exploration prospects and leads. For 2003, we plan to invest approximately $21.7 million in the Gulf Coast region and drill up to eight exploration wells. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures” for a discussion of our planned capital expenditures in 2003.

Acquisitions

     In 2002, we purchased 6.6 Bcfe of proved reserves for direct costs of $3.1 million, at an average cost of $0.47 per Mcfe. The largest single transaction was the acquisition of a minority interest in the Susser #2 well located in Nueces County, Texas for $1.7 million. We are the operator of the well. The remaining $1.2 million was spent to acquire additional working interests in the Overton Field and in several Arkoma Basin wells.

     In 2001, we purchased proved reserves of 4.5 Bcfe for direct costs of $6.5 million, or $1.46 per Mcfe. The purchase included overriding royalty interests in the Arkoma Basin of 2.2 Bcfe, and additional working interests in the Overton Field of 1.9 Bcfe.

     In April 2000, we purchased our initial interest in the Overton Field in Smith County, Texas, from Total Fina Elf for direct costs of $6.1 million. Proved developed producing reserves associated with the purchase were 7.5 Bcfe, for a purchase price per Mcfe of $0.81. The purchase included 16 active gas wells in 13 spacing units, 8,800 contiguous acres in established units and 2,000 additional undeveloped acres outside those units.

     In 1999, we purchased producing properties in the Permian Basin with estimated proved reserves of 9.4 Bcf of natural gas and 576 MBbls of oil, or 12.9 Bcfe. The properties were purchased from Petro-Quest Exploration, a privately held company headquartered in Midland, Texas, for direct costs of $9.4 million. We did not make any producing property acquisitions in 1998.

     As part of our current business strategy, we selectively review opportunities to acquire producing properties and leasehold acreage, focusing in particular on the regions where we have existing operations. In addition, we seek to acquire operational control of properties we believe have significant exploitation and exploration potential.

Capital Expenditures

     We invested a total of $85.2 million in our E&P program and participated in drilling 65 wells during 2002. Of these drilled wells, 45 were successful, 16 were dry and 4 were still in progress at year-end. Our investments were balanced between our core areas of operations, with approximately $18.2 million invested in the Arkoma Basin, $33.6 million in East Texas, $5.4 million in the Permian Basin and Mid-Continent areas, and $28.0 million in the Gulf Coast. Of the $85.2 million invested, approximately $15.5 million was invested in exploratory drilling, $46.1 million in development drilling and workovers, $9.1 million for land and leasehold acquisition and seismic expenditures, $3.1 million for producing property acquisitions, and $11.4 million in capitalized interest and expenses and other technology-related expenditures.

     In 2003, our planned E&P capital budget is $137.1 million, with approximately 83% allocated to drilling. The majority of our investments in 2003 will be directed to the lower-risk part of our E&P portfolio, primarily due to our planned acceleration of the development of the Overton Field in East Texas. In 2003, approximately 73% of our capital will be allocated to lower-risk development drilling activities in the Arkoma Basin ($22.6 million) and East Texas ($78.0 million). The remainder of our capital will be allocated to medium-risk exploration and exploitation in the Permian Basin ($4.8 million), higher risk exploration in South Louisiana ($21.7 million) and capital investments in other frontier areas ($10.0 million). Of the $137.1 million capital budget, approximately $16.1 million will be invested in exploratory drilling,

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$97.2 million in development drilling and workovers, $12.0 million for land and leasehold acquisition and seismic expenditures, and $11.8 million in capitalized interest and expenses and technology-related expenditures.

     We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures” for a discussion of our planned capital expenditures in 2003.

Sales and Major Customers

     Our daily natural gas equivalent production averaged 109.8 MMcfe in 2002, compared to 109.0 MMcfe in 2001 and 97.7 MMcfe in 2000. Our natural gas production was 36.0 Bcf in 2002, compared to 35.5 Bcf in 2001 and 31.6 Bcf in 2000. We also produced 682,000 barrels of oil in 2002, compared to 719,000 barrels of oil in 2001 and 676,000 barrels in 2000. We are targeting production in 2003 to be approximately 42 Bcfe to 44 Bcfe.

     We realized an average wellhead price of $3.00 per Mcf for our natural gas production in 2002, compared to $3.85 per Mcf in 2001 and $2.88 per Mcf in 2000, including the effect of hedges. Our hedging activities lowered the average gas price $0.11 per Mcf in 2002, $0.31 per Mcf in 2001, and $1.04 per Mcf in 2000. Our average oil price realized was $21.02 per barrel in 2002, compared to $23.55 per barrel in 2001 and $22.99 per barrel in 2000, including the effect of hedges. Our hedging activities lowered the average oil price $2.92 in 2002, $0.03 per barrel in 2001 and $6.39 per barrel in 2000.

     Our gas sales to unaffiliated purchasers were 30.6 Bcf in 2002, compared to 30.4 Bcf in 2001 and 23.8 Bcf in 2000. All of our oil production is sold to unaffiliated purchasers. This gas and oil production is sold under contracts that reflect current short-term prices and which are subject to seasonal price swings. These combined gas and oil sales to unaffiliated purchasers accounted for 85% of total E&P revenues in 2002, 83% in 2001 and 76% in 2000.

     Our utility subsidiary, Arkansas Western is the largest single customer for sales of our gas production and the only customer that accounted for more than 10% of our natural gas and oil production revenue in 2002. These sales are made by SEECO primarily under contracts obtained under a competitive bidding process. We refer you to “Natural Gas Distribution—Gas Purchases and Supply” below for further discussion of these contracts. Sales to Arkansas Western accounted for approximately 15% of total E&P revenues in 2002, 17% in 2001 and 24% in 2000. SEECO’s sales to Arkansas Western were 5.4 Bcf in 2002, compared to 5.1 Bcf in 2001 and 7.8 Bcf in 2000. The increase in sales in 2002 was primarily caused by increased supply requirements due to colder weather when compared to 2001. Weather in 2002, as measured in degree days, was 8% colder than in 2001 and 2% warmer than normal. The decrease in sales in 2001 was primarily due to warmer weather and the sale of the utility’s Missouri gas distribution properties in May 2000. Weather in 2001, as measured in degree days, was 9% warmer than both normal and the prior year for Arkansas Western’s service territory. SEECO’s gas production provided approximately 37% of the utility’s requirements in 2002, 33% in 2001 and 42% in 2000. SEECO also owns an unregulated natural gas storage facility that has historically been utilized to help meet its peak seasonal sales commitments. The storage facility is connected to Arkansas Western’s distribution system.

     Future sales to Arkansas Western’s gas distribution systems will be dependent upon our success in obtaining gas supply contracts with the utility systems. In the future, our subsidiaries will continue to bid to obtain these gas supply contracts, although there is no assurance that they will be successful. If successful, we cannot predict the amount of fixed demand charges, if any, that would be associated with the new contracts. We expect future increases in our gas production to come primarily from sales to unaffiliated purchasers. We are unable to predict changes in the market demand and price for natural gas, including changes that may be induced by the effects of weather on demand of both affiliated and unaffiliated customers for our production.

     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. At December 31, 2002, we had hedges in place on 42.6 Bcf of future gas production and 240,000 barrels of future oil production. Subsequent to December 31, 2002 and prior to February 14, 2003, we hedged 3.0 Bcf of 2003 gas production under costless collars with floor prices of $4.00 per Mcf and ceiling prices ranging from $5.85 to $6.20 per Mcf, and 100,000 barrels of future oil production at $29.40 per barrel. We currently have hedges in place on approximately 75% of our targeted 2003 gas production and approximately 65% of our 2003 targeted oil production. We refer you to “Quantitative and Qualitative Disclosures About Market Risks,” for further information regarding our hedge position at December 31, 2002.

     Disregarding the impact of hedges, we expect the average price received for our gas production to be approximately $0.10 to $0.20 per Mcf lower than average spot market prices, as market differentials that reduce the

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average prices received are partially offset by demand charges under the contracts covering our intersegment sales to Arkansas Western. Disregarding the impact of hedges, we expect the average price received for our oil production to be approximately $1.25 per barrel lower than average spot market prices, as market differentials reduce the average prices received.

Competition

     All phases of the oil and gas industry are highly competitive. We compete in the acquisition of properties, the search for and development of reserves, the production and sale of oil and gas and the securing of the labor and equipment required to conduct operations. Our competitors include major oil and gas companies, other independent oil and gas companies and individual producers and operators. Many of these competitors have financial and other resources that substantially exceed those available to us.

     Competition has increased in recent years due largely to the development of improved access to interstate pipelines. Due to our significant leasehold acreage position in Arkansas and our long-time presence and reputation in this area, we believe we will continue to be successful in acquiring new leases in Arkansas. While improved intrastate and interstate pipeline transportation in Arkansas should increase our access to markets for our gas production, these markets will generally be served by a number of other suppliers. Consequently, we will encounter competition that may affect both the price we receive and contract terms we must offer. Outside Arkansas, we are less established and face competition from a larger number of other producers.

Oil Price Controls And Transportation Rates

     Sales of crude oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. Effective January 1, 1995, the Federal Energy Regulatory Commission (the “FERC”) implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser. The implementation of these regulations has not had a material adverse effect on our results of operations.

Federal Regulation of Sales and Transportation of Natural Gas

     Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the FERC. In the past, the federal government has regulated the prices at which gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Commencing in 1992, the FERC issued Order No. 636 and subsequent orders (collectively, “Order No. 636”), which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sales of gas. Order No. 636 also requires pipelines to provide open-access transportation on a basis that is equal for all shippers. Although Order No. 636 does not directly regulate our activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The implementation of these orders has not had a material adverse effect on our results of operations. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In 2000, the FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 are pending judicial review. We cannot predict whether and to what extent FERC’s market reforms will survive judicial review and, if so, whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that we will be affected by any action taken in a materially different way than other natural gas producers and marketers with which we compete. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

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Natural Gas Distribution

     We distribute natural gas to approximately 140,000 customers in northern Arkansas through our subsidiary, Arkansas Western. Our utility continues to capitalize on the healthy economy and sustained customer growth found in its Northwest Arkansas service territory. In April 2001, the U.S. Census Bureau listed Northwest Arkansas as the sixth fastest growing community in the United States. As home to the largest public corporation in the world, Wal-Mart Stores, Inc., the region has experienced significant growth due to its presence in the area. Other large corporations such as Tyson Foods and J.B. Hunt Transportation have also contributed to this area’s development. Approximately 86% of Arkansas Western’s customers are located in this part of the state and, in recent years, Arkansas Western has experienced customer growth of approximately 2% to 3% annually.

     Operating income for our natural gas distribution business was $7.6 million in 2002, compared to $10.3 million in 2001 and $12.6 million in 2000 (excluding the Missouri utility properties). EBITDA generated by our utility segment was $14.0 million in 2002, compared to $17.1 million in 2001 and $20.7 million in 2000 (excluding the Missouri utility properties). We refer you to “Business—Other Items—Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our operating income as derived from our audited financial information. Our operating income and EBITDA decreased primarily due to increased operating costs and expenses and reduced usage per customer brought about by high gas prices. We filed for an $11.0 million annual rate increase with the Arkansas Public Service Commission, or the APSC, in November 2002. The requested increase is the first Arkansas Western has made since 1996. The APSC has ten months to review the filing and reach a decision on the amount of the increase, if any, to be approved, therefore, we expect that any increase granted would be effective during the fall of 2003.

     In June 2000, we announced we were pursuing the sale of our utility operations in Arkansas to fund a $109.3 million judgment against us, which we refer to as the Hales judgment. Although we received several serious expressions of interest from bona fide parties, we did not receive an offer that was acceptable to us. We are no longer pursuing a sale of the utility system and intend to operate the Arkansas utility properties as a continuing part of our business.

     On May 31, 2000, we completed the sale of our Missouri gas distribution assets for $32.0 million. The sale resulted in a pre-tax gain of approximately $3.2 million and proceeds from the sale were used to repay outstanding indebtedness.

Gas Purchases and Supply

     Arkansas Western purchases its system gas supply through a competitive bidding process implemented in October 1998, and directly at the wellhead under long-term contracts with flexible pricing provisions. In 2002, SEECO successfully bid on gas supply packages representing approximately two-thirds of the requirements for Arkansas Western for 2003.

     Arkansas Western also purchases gas for its system supply from unaffiliated suppliers accessed by interstate pipelines. These purchases are under firm contracts with one-year to two-year terms. The rates charged by most suppliers include demand components to ensure availability of gas supply and a commodity component that is based on monthly indexed market prices. The pipeline transportation rates include demand charges to reserve pipeline capacity and commodity charges based on volumes transported. Less than 5% of the utility’s gas purchases are under take-or-pay contracts. Currently, Arkansas Western believes that it does not have a significant exposure to take-or-pay liabilities resulting from these contracts and expects to be able to continue to satisfactorily manage these contracts.

     Arkansas Western has a regulated natural gas storage facility connected to its distribution system in Northwest Arkansas that it utilizes to help meet its peak seasonal demands. The utility also owns a liquefied natural gas facility and contracts with an interstate pipeline for additional storage capacity to serve its system in the northeastern part of the state. These contracts involve demand charges based on the maximum deliverability, capacity charges based on the maximum storage quantity, and charges for the quantities injected and withdrawn.

     The utility’s rate schedules include purchased gas adjustment clauses whereby the actual cost of purchased gas above or below the level included in the base rates is permitted to be billed or is required to be credited to customers. Each month, the difference between actual costs of purchased gas and gas costs recovered from customers is deferred. The deferred differences are billed or credited, as appropriate, to customers in subsequent months.

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Markets and Customers

     Arkansas Western provides natural gas to approximately 123,000 residential, 16,400 commercial, and 200 industrial customers, while also providing gas transportation services to approximately 70 end-use and off-system customers. Total gas throughput in 2002 was 27.3 Bcf, compared to 27.1 Bcf in 2001 and 33.4 Bcf in 2000. The higher volumes in 2002 were due to weather that was 8% colder than in 2001 and an increase in volumes delivered to the utility’s end-use transportation customers. The decrease in 2001 resulted from the loss of throughput associated with the sale of the utility’s Missouri assets in May 2000 and warmer weather. Off-system transportation volumes were 2.2 Bcf in 2002 and 3.1 Bcf in both 2001 and 2000.

     Residential and Commercial. Approximately 87% of the utility’s revenues in 2002 were from residential and commercial markets. Residential and commercial customers combined accounted for 56% of total gas throughput for the gas distribution segment in 2002, compared to 54% in 2001 and 55% in 2000. Gas volumes sold to residential customers were 9.0 Bcf in 2002, compared to 8.4 Bcf in 2001 and 10.9 Bcf in 2000. Gas sold to commercial customers totaled 6.2 Bcf in 2002, 6.1 Bcf in 2001 and 7.6 Bcf in 2000. The increases in gas volumes sold in 2002 were due to weather that was 8% colder than in 2001. The decreases in gas volumes sold in 2001 were due to the sale of the Missouri utility properties and warmer weather. Weather during 2001 was 9% warmer than both normal and the prior year.

     The gas heating load is one of the most significant uses of natural gas and is sensitive to outside temperatures. Sales, therefore, vary throughout the year. Profits, however, have become less sensitive to fluctuations in temperature recently as tariffs implemented in Arkansas contain a weather normalization clause to lessen the impact of revenue increases and decreases that might result from weather variations during the winter heating season.

     Industrial and End-use Transportation. Deliveries to Arkansas Western’s industrial and end-use transportation customers were 9.9 Bcf in 2002, 9.5 Bcf in 2001 and 11.8 Bcf in 2000. The decrease in deliveries in 2001 was primarily due to the sale of the utility’s Missouri properties. No industrial customer accounts for more than 9% of Arkansas Western’s total throughput. Arkansas Western offers a transportation service that allows larger business customers to obtain their own gas supplies directly from other suppliers. A total of 73 customers are currently using the transportation service.

Competition

     Arkansas Western has experienced a general trend in recent years toward lower rates of usage among its customers, largely as a result of conservation efforts that we encourage. We experience increasing competition from alternative fuels such as electricity, fuel oil, and propane. Arkansas Western has historically maintained a substantial price advantage over these fuels for most applications, enabling us to achieve excellent market penetration levels. However, the high gas prices experienced in the 2000–2001 heating season temporarily eroded the price advantage in some markets. Arkansas Western has made progress in regaining price advantage in its markets as gas prices have declined from the levels experienced during the winter of 2000–2001. Arkansas Western also has the ability through its approved tariffs to lower its rates to large customers to be competitive with available alternative fuels or if the threat of bypass exists. This tariff is likely to be eliminated in the pending rate case and replaced with an alternative mechanism that will require APSC approval for rate discounts.

Regulation

     Arkansas Western’s utility rates and operations are regulated by the APSC. We operate through municipal franchises that are perpetual by virtue of state law. These franchises, however, may not be exclusive within a geographic area. As the regulatory focus of the natural gas industry has shifted from the federal level to the state level, some utilities across the nation are required to unbundle residential sales services from transportation services in an effort to promote greater competition. Although no such legislation or regulatory directives related to natural gas are presently pending in Arkansas, Arkansas Western is aggressively controlling costs and constantly reviewing issues such as system capacity and reliability, obligation to serve, rate design and stranded or transition costs.

     In Arkansas, legislation was adopted in 2001 for the deregulation of the retail sale of electricity between October 2003 and October 2005. In December 2001, the APSC submitted to the legislature its annual report on the development of electric deregulation and recommended that the legislature consider suspending deregulation until 2010 or 2012.

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Furthermore, legislation has been recently introduced seeking to repeal the deregulation of the retail sale of electricity. It is unknown whether additional legislation will be adopted or, if it is adopted, what its final form will be. If electric deregulation occurs in Arkansas, legislative or regulatory precedents may be set that would also affect natural gas utilities in the future. These effects may include further unbundling of services and the regulatory treatment of stranded costs.

     In November 2002, Arkansas Western filed a request with the APSC for an adjustment in its rates totaling $11.0 million, or 9.1%, annually. The requested increase is the first Arkansas Western has made since 1996. The APSC has ten months to review the filing and reach a decision. As a result, Arkansas Western expects that any increase granted would be effective in the fall of 2003. Arkansas Western’s most recent rate increase was approved in December 1996 for the utility’s Northwest region and in December 1997 for its Northeast region. The APSC approved annual rate increases of $5.1 million and $1.2 million, respectively.

     In February 2001, the APSC approved a 90-day temporary tariff to collect additional gas costs not yet billed to customers through the normal purchased gas adjustment clause in the utility’s approved tariffs. Arkansas Western had under-recovered purchased gas costs of $12.9 million in its current assets at December 31, 2000. The amount of under-recovered purchased gas costs increased significantly during January 2001 as a result of rapidly increasing gas costs. The temporary tariff allowed the utility accelerated recovery of the gas costs it had incurred during the 2000–2001 winter heating season. In April 2002, Arkansas Western filed a revised purchased gas adjustment clause that provides better matching between the time the gas costs are incurred and the time the costs are recovered. The APSC approved the new clause in May 2002. At December 31, 2001, Arkansas Western had over-recovered purchased gas costs of $8.2 million. At December 31, 2002, Arkansas Western had approximately $5.7 million of over-recovered purchased gas costs.

     In May 1999, the staff of the APSC initiated a proceeding in which it sought an annual reduction of approximately $2.3 million in the rates Arkansas Western charges its customers in Northwest Arkansas. Staff’s position was based on various adjustments to the utility’s rate base, operating expenses, capital structure and rate of return. A large portion of the proposed reduction was based on a downward adjustment to the utility’s current return on equity authorized by the APSC in 1996. During the third quarter of 1999, Arkansas Western reached agreement with the staff and the APSC to resolve this issue and to close several other open dockets. In the settlement agreement, Arkansas Western agreed to reduce its rates collected from customers on a prospective basis in the amount of $1.4 million annually, effective December 1, 1999.

     Gas distribution revenues in future years will be impacted by customer growth and rate increases allowed by the APSC. In recent years, Arkansas Western has experienced customer growth of approximately 2% to 3% annually in its Northwest Arkansas service territory, while it has experienced little or no growth in its service territory in Northeast Arkansas. Based on current economic conditions in its service territories, we expect this trend in customer growth to continue.

     We refer you to “Risk Factors—We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” for a discussion of the impact that government regulation has on our natural gas distribution business.

Marketing, Transportation and Other

     Operating income from the marketing, transportation and other segment, which includes income from real property held by our subsidiary, A.W. Realty Company, was $2.9 million in 2002, compared to $3.0 million in 2001 and $2.5 million in 2000. EBITDA for this segment was $2.8 million in 2002, compared with $2.4 million in 2001 and $3.0 million in 2000. We refer you to “Business—Other Items—Reconciliation of Non-GAAP Measures” for a table that reconciles EBITDA with our operating income as derived from our audited financial information.

Gas Marketing

     Our gas marketing subsidiary, Southwestern Energy Services Company, was formed in 1996 to better enable us to capture downstream opportunities which arise through marketing and transportation activity. Through utilization of our existing asset base, we are focused on creating and capturing value beyond the wellhead.

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     Our current marketing operations primarily relate to the marketing of our own gas production and some third-party natural gas that is primarily sold to industrial customers connected to our gas distribution systems. Our operating income from marketing was $2.7 million on revenues of $131.1 million in 2002, compared to $2.7 million on revenues of $190.3 million in 2001, and $2.5 million on revenues of $207.7 million in 2000. We marketed 45.5 Bcf of natural gas in 2002, compared to 49.6 Bcf in 2001 and 59.6 Bcf in 2000. In late 2000, we began marketing less third-party natural gas in an effort to reduce our potential credit risk and concentrated more on marketing our affiliated production. Of the total volumes marketed, purchases from our E&P subsidiaries accounted for 67% in 2002, 66% in 2001 and 33% in 2000.

Transportation

     In January 1998, we entered into an agreement with Enogex Inc., a subsidiary of OGE Energy Corp. (“Enogex”), to expand the NOARK Pipeline and provide access to Oklahoma gas supplies through an integration of NOARK Pipeline with the Ozark Gas Transmission System. Ozark was a 437-mile interstate pipeline system that began in eastern Oklahoma and terminated in eastern Arkansas. Enogex acquired Ozark and contributed the pipeline system to the NOARK partnership. Enogex also acquired the NOARK partnership interests not held by us. On July 1, 1998, the FERC authorized the operation and integration of Ozark and NOARK Pipeline as a single, integrated pipeline. Enogex funded the acquisition of Ozark and the expansion and integration with NOARK Pipeline that resulted in our interest in the partnership decreasing from approximately 48% to 25%, with Enogex owning the remaining 75% interest. There are also provisions in the agreement with Enogex which allow for revenue allocations to us above our 25% partnership interest if certain minimum throughput and revenue assumptions are not met.

     The new integrated system, known as Ozark Pipeline, became operational November 1, 1998, and includes 749 miles of pipeline with a total throughput capacity of 330.0 MMcf per day. Deliveries are currently being made by the pipeline to portions of Arkansas Western’s distribution systems and to the interstate pipelines with which it interconnects. The average daily throughput for the pipeline was 168.1 MMcf per day in 2002, compared to 134.1 MMcf per day in 2001 and 188.2 MMcf per day in 2000.

     At December 31, 2002, Arkansas Western had transportation contracts with Ozark Pipeline for 66.9 MMcf per day of firm capacity. These contracts expire in 2003 and are renewable annually thereafter until terminated with 180 days’ notice. These contracts are currently being renegotiated. The merged pipeline system now has greater access to major gas producing fields in Oklahoma. We expect that the pipeline’s additional throughput will create new marketing and transportation opportunities for us and reduce the losses NOARK has incurred in the past. The merged pipeline also provides our utility systems with additional access to gas supply. Our share of NOARK’s results of operations were losses of $0.3 million in 2002, $1.5 million in 2001 and $1.8 million in 2000. The improvements in operating results since 2000 result primarily from the ability to collect higher transportation rates on interruptible volumes. We believe that we will be able to continue to reduce the losses we have experienced on the NOARK project and expect our investment in NOARK to be realized over the life of the system.

Other

     Our wholly owned subsidiary, A. W. Realty Company, owns an interest in approximately 150 acres of real estate, most of which is undeveloped. A.W. Realty’s real estate development activities are concentrated on a 130-acre tract of land located near a growing part of Fayetteville, Arkansas. A.W. Realty continues to review with a joint venture partner various options for developing this property that would minimize our initial capital expenditures, but still enable us to retain an interest in any appreciation in value.

Competition

     Our gas marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have. Some of these competitors are affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. Other factors affecting competition are cost and availability of alternative fuels, level of consumer demand, and cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with producers and end-users.

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     The NOARK Pipeline previously competed with two interstate pipelines, one of which was the Ozark system, to obtain gas supplies for transportation to other markets. The integration with Ozark provides increased supplies to transport to both local markets and markets served by the three major interstate pipelines that Ozark Pipeline connects with in eastern Arkansas. We believe that the Ozark Pipeline will provide the additional gas supplies necessary to compete more effectively for the transportation of natural gas to end-users and markets served by the interstate pipelines.

Regulation

     Prior to the integration with Ozark, the operations of NOARK Pipeline were regulated by the APSC. The APSC had established a maximum transportation rate of approximately $0.285 per dekatherm. The integration of NOARK Pipeline with Ozark resulted in an interstate pipeline system subject to FERC regulations and FERC-approved tariffs. The FERC has set the maximum transportation rate of Ozark Pipeline at $0.2867 per dekatherm.

Other Items

Reconciliation of Non-GAAP Measures

     EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. We have included information concerning EBITDA in this Form 10-K because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in our industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies.

     We believe that operating income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA as defined with our operating income, as derived from our audited financial information for the years-ended December 31, 2002, 2001 and 2000:

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Environmental Matters

     Our operations are subject to numerous federal, state and local laws and regulations including the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Clean Water Act, the Clean Air Act and similar state legislation. These laws and regulations:

	•		require permits for drilling wells;
	•		restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
	•		limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
	•		impose substantial liabilities for pollution resulting from our operations.

     Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the natural gas and oil industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

     The Oil Pollution Act, as amended, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States’ waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

     CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

     The Resource Conservation and Recovery Act, as amended, or the RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

     We currently own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil. Although we have utilized

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operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, most of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the Clean Water Act, the RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

     The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the Environmental Protection Agency, or the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

Employees

     At December 31, 2002, we had 522 total employees, including 346 employed by our natural gas utility, of which 30 are represented under a collective bargaining agreement. We believe that our relationships with our employees are good.

RISK FACTORS

     In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. The risk factors described below are not necessarily exhaustive and investors are encouraged to perform their own investigation with respect to us and our business. Investors should also read the other information included in this Form 10-K, including our financial statements and the related notes.

We may have difficulty financing our planned growth.

     We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our drilling program. In the future, we may require additional financing, in addition to cash generated from our operations, to fund our planned growth. We cannot be certain that additional financing will be available to us on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Natural gas and oil prices are volatile. Volatility in natural gas and oil prices can adversely affect our results and the price of our common stock. This volatility also makes valuation of natural gas and oil producing properties difficult and can disrupt markets.

     Natural gas and oil prices have historically been, and are likely to continue to be, volatile. The prices for natural gas and oil are subject to wide fluctuation in response to a number of factors, including:

	•		relatively minor changes in the supply of and demand for natural gas and oil;
	•		market uncertainty;
	•		worldwide economic conditions;
	•		weather conditions;

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	•		import prices;
	•		political conditions in major oil producing regions, especially the Middle East;
	•		actions taken by OPEC;
	•		competition from other sources of energy; and
	•		economic, political and regulatory developments.

The prices for natural gas and oil could be significantly affected by the prospect and outcome of war in Iraq, for example.

     Price volatility makes it difficult to budget and project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire. In addition, unusually volatile prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties. Our quarterly results of operations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performance. In recent years, natural gas and oil price volatility has become increasingly severe.

A substantial or extended decline in natural gas and oil prices would have a material adverse affect on us.

     A substantial or extended decline in natural gas and oil prices would have a material adverse effect on our financial position, results of operations, access to capital and the quantities of natural gas and oil that may be economically produced. A significant decrease in price levels for an extended period would negatively affect us in several ways including:

	•		our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;
	•		certain reserves would no longer be economic to produce, leading to both lower proved reserves and cash flow; and
	•		access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

Consequently, our revenues, profitability and liquidity would suffer.

Lower natural gas and oil prices may cause us to record ceiling test write-downs.

     We use the full cost method of accounting for our natural gas and oil operations. Accordingly, we capitalize the cost to acquire, explore for and develop natural gas and oil properties. Under the full cost accounting rules of the SEC, the capitalized costs of natural gas and oil properties—net of accumulated depreciation, depletion and amortization, and deferred income taxes—may not exceed a “ceiling limit.” This is equal to the present value of estimated future net cash flows from proved natural gas and oil reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects.

     These rules generally require pricing future natural gas and oil production at the unescalated natural gas and oil prices in effect at the end of each fiscal quarter. They also require a write-down if the ceiling limit is exceeded, even if prices declined for only a short period of time.

     If natural gas and oil prices fall significantly, a write-down may occur. Write-downs required by these rules do not impact cash flow from operating activities but do reduce net income and shareholders’ equity.

Repercussions from any terrorist act or from armed hostilities in the United States or abroad could harm our revenues, business operations, profitability or growth.

     The terrorist attacks that occurred on September 11, 2001 caused significant instability in the world’s markets. There can be no assurance that the armed hostilities will not escalate or that these terrorist attacks, or the United States’ responses to them, will not lead to further acts of terrorism and civil disturbances in the United States or elsewhere,

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which may further contribute to the economic instability in the United States where we operate. Any armed conflict, civil unrest or additional terrorist activities, and the attendant political instability and societal disruption, could reduce demand for our products or disrupt our ability to conduct our exploration, production, development and marketing activities, which could harm our business.

The natural gas and oil reserves data we report are only estimates and may prove to be inaccurate.

     There are numerous uncertainties, including many factors beyond our control inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development expenditures. Reserve data represent only estimates. In addition, the estimates of future net cash flows from our proved reserves and their present value are based upon various assumptions about future production levels, prices and costs that may prove to be incorrect over time. Any significant variation from these assumptions could result in the actual quantity of our reserves and future net cash flows being materially different from the estimates. In addition, our estimates of reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, operating and development costs and other factors.

     At December 31, 2002, approximately 23% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assume that we can and will make these expenditures and conduct these operations successfully, which may not occur.

If we fail to find or acquire additional reserves, our reserves and production will decline materially from their current levels.

     The rate of production from natural gas and oil properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced. Future natural gas and oil production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future.

     Our exploration and production, marketing and transportation operations are regulated extensively at the federal, state and local levels. We have made and will continue to make large expenditures in our efforts to comply with these laws and regulations, including environmental, health and safety regulation. The natural gas and oil regulatory environment could change in ways that might substantially increase these costs. Regulated matters include permits for exploration, development and production operations, such as permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow of oil and gas wells below actual production capacity. In addition, at the U.S. federal level, the FERC regulates interstate transportation of natural gas under the NGA. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

     As an owner or lessee and operator of natural gas and oil properties, we are subject to various federal, state and local regulations and laws relating to the discharge of substances into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in or additions to regulations or laws regarding the protection of the environment could significantly increase our costs of compliance, or otherwise adversely affect our business.

     One of the responsibilities of owning and operating natural gas and oil properties is paying for the cost of abandonment. Effective January 1, 2003, companies are required to reflect abandonment costs as a liability on their balance sheets. We may incur significant abandonment costs in the future which could adversely affect our financial results.

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Natural gas and oil drilling and producing operations involve various risks.

     Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We rely to a significant extent on seismic data and other advanced technologies in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that natural gas or oil is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.

     The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements and the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

     Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.

     We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. However, our insurance does not protect us against all operational risks. For example, we do not maintain business interruption insurance. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant costs not covered by insurance that could have a material adverse effect upon our financial results.

We cannot control activities on properties we do not operate. Failure to fund capital expenditure requirements may result in reduction or forfeiture of our interests in some of our non-operated projects.

     Other companies operate some of the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that will be outside our control, including the operator’s expertise and financial resources, approval of other participants in drilling wells and selection of technology.

     When we are not the majority owner or operator of a particular natural gas or oil project, we may have no control over the timing or amount of capital expenditures associated with such project. If we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Shortages of oil field equipment, services and qualified personnel could adversely affect our results of operations.

     The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. We cannot be certain when we will experience shortages or price increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

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Our business could be adversely affected by competition with other companies.

      The natural gas and oil industry is highly competitive, and our business could be adversely affected by companies that are in a better competitive position. As an independent natural gas and oil company, we frequently compete for reserve acquisitions, exploration leases, licenses, concessions, marketing agreements, equipment and labor against companies with financial and other resources substantially larger than we possess. Many of our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating in our core areas for a much longer time than we have or have established strategic long-term positions in geographic regions in which we may seek new entry.

We depend upon our management team and our operations require us to attract and retain experienced technical personnel.

      The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced management team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us. The loss of members of our management team or other highly qualified technical professionals could have a material adverse effect on our business, financial condition and operating results.

Our level of indebtedness may adversely affect operations and limit our growth.

      The terms of the indenture relating to our outstanding senior notes and our revolving credit facility impose significant restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, including:

	•		incurring additional debt, including guarantees of indebtedness;
	•		paying dividends on stock, redeeming stock or redeeming subordinated debt;
	•		making investments;
	•		creating liens on our assets; and
	•		selling assets.

      Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:

	•		requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
	•		limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
	•		limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
	•		detracting from our ability to successfully withstand a downturn in our business or the economy generally.

      Our ability to comply with the covenants and other restrictions in the agreements governing our debt may be affected by events beyond our control, including prevailing economic and financial conditions. If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our repayment of outstanding debt. We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt.

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The terms of our debt, including our credit facility and our indentures, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such proposed offering, refinancing or sale of assets can be successfully completed.

      At December 31, 2002, we had long-term indebtedness of $342.4 million, excluding $42.6 million relating to our several guarantee of NOARK’s debt obligation. Indebtedness under our revolving credit facility was $117.4 million of our total long-term indebtedness.

Our hedging activities may prevent us from benefiting from price increases, may reduce our revenues and may expose us to other risks.

      To reduce our exposure to fluctuations in the prices of natural gas and oil, we enter into hedging arrangements with respect to a portion of our expected production. We currently have hedges on approximately 75% of our targeted 2003 natural gas production and approximately 65% of our targeted 2003 oil production. Our hedging activities reduced revenues by $6.1 million in 2002, $10.3 million in 2001 and $39.3 million in 2000. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

      In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

	•		our production is less than expected;
	•		there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
	•		the counterparties to our futures contracts fail to perform the contracts; or
	•		a sudden, unexpected event materially impacts natural gas or oil prices.

      In addition, future market price volatility could create significant changes to the hedge positions reflected in our financial statements. We refer you to “Quantitative and Qualitative Disclosure about Market Risks.”

      We could be harmed if the capital markets do not recover or continue to materially decline, or if interest rates substantially rise.

      If the capital markets do not recover or continue to materially decline, our earnings would decrease as a result of pension expenses that we would incur. In addition, we might not be able to finance our operations on terms we consider acceptable and our net cash flows could decrease due to higher interest rates.

GLOSSARY OF CERTAIN INDUSTRY TERMS

      The definitions set forth below shall apply to the indicated terms as used in this Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“Bcf” One billion cubic feet of gas.

“Bcfe” One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

“Bopd” Barrels of oil produced per day.

“Btu” British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

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“Dekatherm” A thermal unit of energy equal to 1,000,000 British thermal units (Btu’s), that is, the equivalent of 1,000 cubic feet of gas having a heated content of 1,000 Btu’s per cubic foot.

“Development drilling” The drilling of a well within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Downspacing” The process of drilling additional wells within a defined producing area to increase recovery of natural gas and oil from a known reservoir.

“EBITDA” Represents net income attributable to common stock plus interest, income taxes, depreciation, depletion and amortization and non-cash ceiling test write-downs of oil and gas properties. We refer you to “Business—Other Items—Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our operating income as derived from our audited financial information.

“Exploratory prospects or locations” A location where a well is drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“Finding and development costs” Costs associated with acquiring and developing proved natural gas and oil reserves which are capitalized pursuant to generally accepted accounting principles, including any capitalized general and administrative expenses.

“Farm-in or farm-out” An agreement under which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

“Gross acreage or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“Infill drilling” Drilling wells in between established producing wells, see also “Downspacing.”

“LIBOR” Represents the London Inter-Bank Overnight Rate of interest.

“MBbls” One thousand barrels of crude oil or other liquid hydrocarbons.

“Mcf” One thousand cubic feet of natural gas.

“Mcfe” One thousand cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

“MMBbls” One million barrels of crude oil or other liquid hydrocarbons.

“MMBtu” One million Btu’s.

“MMcf” One million cubic feet of natural gas.

“MMcfe” One million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

“Net acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells.

“Net revenue interest” Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

“NYMEX” The New York Mercantile Exchange.

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“Operating interest” An interest in natural gas and oil that is burdened with the cost of development and operation of the property.

“Play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.

“Producing property” A natural gas and oil property with existing production.

“Proved developed reserves” Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

“Proved reserves” The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves” Reserves that are expected to be recovered from new wells on developed acreage where the subject reserves cannot be recovered without drilling additional wells.

“PV-10” When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Also referred to as “present value.”

“Recomplete” This term refers to the technique of drilling a separate well-bore from all existing casing in order to reach the same reservoir, or redrilling the same well-bore to reach a new reservoir after production from the original reservoir has been abandoned.

“Royalty interest” An interest in a natural gas and oil property entitling the owner to a share of oil or gas production free of production costs.

“Step-out well” A well drilled adjacent to a proven well but located in an unproven area; a well located a “step out” from proven territory in an effort to determine the boundaries of a producing formation.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“Well spacing” The regulation of the number and location of wells over a gas or oil reservoir, as a conservation measure. Well spacing is normally accomplished by order of the regulatory conservation commission.

“Working interest” An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

“Workovers” Operations on a producing well to restore or increase production.

“WTI” West Texas Intermediate, the benchmark crude oil in the United States.

ITEM 2. PROPERTIES

      For additional information about our natural gas and oil operations, we refer you to Notes 5 and 6 to the financial statements. For information concerning capital expenditures, we refer you to “Management’s Discussion and Analysis of

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Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures”. We also refer you to “Selected Financial Data” for information concerning natural gas and oil produced.

      The following table provides information concerning miles of pipe of our gas distribution systems. For a further description of Arkansas Western’s properties, we refer you to “Business—Natural Gas Distribution.”

      The following information is provided to supplement that presented in Item 8. For a further description of our natural gas and oil properties, we refer you to “Business—Exploration and Production.”

Leasehold acreage as of December 31, 2002:

Producing wells as of December 31, 2002:

Wells drilled during the year:

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Wells in progress as of December 31, 2002:

      During 2002, we were required to file Form 23, “Annual Survey of Domestic Natural Gas and Oil Reserves,” with the Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note 6 to the financial statements in Item 8 to this Report. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties where we are the operator.

Title to Properties

      We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations on those properties that we operate, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties that we operate.

ITEM 3. LEGAL PROCEEDINGS

      We are subject to laws and regulations relating to the protection of the environment. Our 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 our financial position or reported results of operations.

      We are subject to litigation and claims that have arisen in the ordinary course of business. We accrue 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 our operations or on our financial position.

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

      No matters were submitted during the fourth quarter of the fiscal year ended December 31, 2002, to a vote of security holders, through the solicitation of proxies or otherwise.

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Executive Officers of the Registrant

      Mr. Korell was elected as Chairman of the Board in May 2002 and has served as Chief Executive Officer since January 1999 and President since October 1998. He joined us in 1997 as Executive Vice President and Chief Operating Officer. From 1992 to 1997, he was employed by American Exploration Company where he was most recently Senior Vice President-Operations. From 1990 to 1992, he was Executive Vice President of McCormick Resources and from 1973 to 1989, he held various positions with Tenneco Oil Company, including Vice President, Production.

      Mr. Kerley was appointed to his present position in December 1999. Previously, he served as Senior Vice President and Chief Financial Officer from 1998 to 1999, Senior Vice President-Treasurer and Secretary from 1997 to 1998, Vice President-Treasurer and Secretary from 1992 to 1997, and Controller from 1990 to 1992. Mr. Kerley also served as the Chief Accounting Officer from 1990 to 1998.

      Mr. Lane was appointed to his present position in December 2001. Previously, he served as Senior Vice President from February 2001 and Vice President-Exploration from February 1999. Mr. Lane joined us in February 1998 as Manager-Exploration. From 1993 to 1998, he was employed by American Exploration Company where he was most recently Offshore Exploration Manager. Previously, he held various managerial and geological positions at FINA, Inc. and Tenneco Oil Company.

      Mr. Boling was appointed to his present position in December 2002. He joined us as Senior Vice President, General Counsel and Secretary in January 2002. Prior to joining the Company, Mr. Boling had a private law practice in Houston specializing in the natural gas and oil industry from 1993 to 2002. Previously, Mr. Boling was a partner with Fulbright and Jaworski L.L.P. where he was employed from 1982 to 1993.

      Mr. Stevens has served us in his present position since December 1997. Previously, he served as Vice President of Arkansas Western Gas Company from 1988 to 1997.

      All officers are elected at the Annual Meeting of the Board of Directors for one-year terms or until their successors are duly elected. There are no arrangements between any officer and any other person pursuant to which he was selected as an officer. There is no family relationship between any of the named executive officers or between any of them and our directors.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

      Our common stock is traded on the New York Stock Exchange under the symbol “SWN.” At December 31, 2002, we had 2,079 shareholders of record. The following prices represent the range of high and low intra-day market prices of our common stock on the New York Stock Exchange for the periods indicated.

      We have indefinitely suspended payment of quarterly dividends on its common stock. Additionally, at the present time, the payment of dividends is prohibited by our current revolving credit facility.

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ITEM 6. SELECTED FINANCIAL DATA

      The following table sets forth a summary of selected historical financial information for each of the years in the six-year period ended December 31, 2002. This information and the notes thereto is derived from our financial statements. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data.”