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

For the fiscal year ended December 31, 2004

Commission file number 1-08246

(Exact name of Registrant as specified in its charter)

        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 aggregate market value of the voting stock held by non-affiliates of the Registrant was $1,016,483,812 based on the New York Stock Exchange --Composite Transactions closing price on June 30, 2004, of $28.67. For purposes of this calculation, the Registrant has assumed that its directors and executive officers are affiliates.

        The number of shares outstanding as of March 3, 2005, of the Registrant's Common Stock, par value $0.10, was 36,456,066.

        Document incorporated by reference: Portions of the Registrant's Definitive Proxy Statement to be filed with respect to the Annual Meeting of Shareholders to be held on May 11, 2005 are incorporated by reference into Part III of this Form 10-K.

        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, or the Exchange Act. 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, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonably practicable after they are filed with the Securities and Exchange Commission, or the SEC, on our website at www.swn.com. Our corporate governance guidelines and the charters of the Audit, Compensation, Nominating and Retirement Committees of our Board of Directors are available on our website, and are available in print free of charge to any shareholder upon request.

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        Southwestern Energy Company is an integrated energy company primarily focused on the exploration and production of natural gas. We were organized under the laws of Arkansas over 75 years ago and originally operated 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 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), Diamond "M" Production Company and Overton Partners, L.L.C., a wholly-owned subsidiary of SEPCO. SEECO operates exclusively in Arkansas, holds a large base of both developed and undeveloped gas reserves and conducts an ongoing drilling program in the Arkansas part of the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Arkoma Basin, the Permian Basin of Texas and New Mexico, and in Louisiana and East Texas. Diamond "M" has interests in properties in the Permian Basin of Texas. Overton Partners 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 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 145,000 retail customers. Arkansas Western is the largest single purchaser of SEECO's gas production.

3. Marketing -- As a complement to our other businesses, we provide marketing services in each of 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.

        Our E&P business has increasingly contributed to our financial results primarily due to the general increase in natural gas and crude oil commodity prices and the growth in our production volumes. In 2004, 90% of our operating income and earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, were generated from our E&P business. Our natural gas distribution and marketing and transportation businesses each generated 5% of our operating income and generated 6% and 4% of our EBITDA in 2004, respectively. In 2003, our E&P business generated 87% of our operating income and EBITDA, while the natural gas distribution and marketing and transportation businesses generated 7% and 6% of our operating income and 9% and 4% of our EBITDA, respectively. In 2002, our E&P, natural gas distribution and marketing and transportation businesses generated 78%, 16% and 6% of our operating income, respectively, and 83% , 14% and 3% of our EBITDA, respectively. We refer you to "Business Overview -- 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 net income as derived from our audited financial information.

        Our business strategy is focused on providing long-term growth in the net asset value of our business. Within the E&P segment, 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 creating at least $1.30 of discounted pre-tax PVI for each dollar we invest in our E&P business. Our actual PVI results are utilized to help determine the allocation of our future capital investments. We are also focused on creating and capturing additional value beyond the wellhead through our natural gas distribution, marketing and transportation businesses. To further our business strategy, we provide stock and cash incentives for our key employees. Cash incentives are based on the achievement of certain o verall performance targets as well as segment specific measures. For eligible employees in our E&P segment, these measures

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include production, proved reserve additions, lease operating expenses and general and administrative expenses per unit of production and PVI added per dollar invested.

                        The key elements of our E&P business strategy are:

• Continue to Exploit and Develop Existing Asset Base. We seek to maximize the value of our existing asset base by developing and exploiting properties that have 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.

• Focus on Growth Through New Exploration and Development Activities. We are focused on increasing reserves and production through the drillbit. As part of this effort, we actively seek to develop natural gas and oil plays as well as other new exploration projects with significant exploration and exploitation potential. We have personnel dedicated to the research and identification of active and potential plays, focusing on both conventional exploration plays and unconventional plays (including coal bed methane, shale gas and basin-centered gas) as well as the technological aspects such as horizontal drilling and fracture techniques. New prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria. In August 2004, we announced that we are testing a new unconventional shale gas play on the Arkansas side of the Arkoma Basin. This play, which we refer to as the "Fayetteville Shale play," was an outgrowth of our focus on new exploration and development projects.

• 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.

• Acquiring Selective Properties. 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 may have significant unrealized exploration and exploitation potential. In 2004, we purchased 5.8 Bcfe of proved reserves for $14.2 million at an average cost of $2.45 per Mcfe. Almost all of this investment related to the acquisition of additional working interest in our River Ridge discovery in the Permian Basin. In 2003 and 2002, we invested $3.0 million and $3.1 million for the acquisition of 1.1 Bcfe of proved reserves and 6.6 Bcfe of proved reserves, respectively.

        Amended and Restated Credit Facility and Rating Downgrade. In January 2005, we amended and restated our $300 million revolving credit facility that was due to expire in January 2007, increasing the borrowing capacity to $500 million and extending the expiration to January 2010. The amended and restated revolving credit facility replaced the $300 million credit facility and another smaller credit facility. As of March 3, 2005, we had approximately $420 million of available capacity under this revolving credit facility. On January 3, 2005, Standard & Poor's Ratings Services lowered our corporate credit rating to 'BBB-' from 'BBB'. We continue to be rated Ba2 by Moody's.

        Utility Files for Rate Adjustment. Our utility filed for a $9.7 million annual rate increase with the Arkansas Public Service Commission, or APSC, in December 2004. The APSC has ten months to review the filing and determine the amount of the increase, if any. Any rate increase allowed would likely be implemented in the fourth quarter of 2005.

        2005 Planned Capital Expenditures and Guidance. In December 2004, we announced a planned capital investment program for 2005 of up to $352.7 million, an increase of 20% over our 2004 capital program. Our 2005 capital program includes up to $339.0 million for our E&P segment and $13.7 million for improvements to our utility systems and for other corporate purposes. The increased capital program is expected to be funded by internally-generated cash flow and borrowings under our revolving credit facility. We also announced our targeted 2005 oil and gas production of approximately 61.0 to 63.0 Bcfe, an increase of approximately 13% to 17% over our production in 2004, our estimates for certain expenses and ranges for certain financial results under various commodity price scenarios.

        Announcement of Fayetteville Shale Play. On August 17, 2004, we announced our Fayetteville Shale play. Our acreage position in the play at December 31, 2004, was approximately 557,000 net acres in the undeveloped play area and approximately 125,000 net developed acres held by conventional production and located in the portion of the Arkoma Basin that is primarily within the boundaries of our utility gathering system in Arkansas, which we refer to as the

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"Fairway." At December 31, 2004, we had drilled and completed 21 vertical test wells in the Fayetteville Shale. Based on results achieved to date and assuming that the oil and gas price environment remains favorable, we expect to allocate up to $100.2 million of our 2005 E&P capital to our Fayetteville Shale play, which would include drilling up to 160 to 170 wells.

        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. Our executives have assembled a high-quality team of management and technical professionals with knowledge and experience in the geologic basins in which we have operations, including experienced explorationists with proven track records of finding natural gas and oil. Our E&P business is organized into asset management teams based on the geographic location of our exploration and development projects.

        We operate our E&P business in four general regions -- the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast. Operating income for our E&P business was $164.6 million and EBITDA was $231.8 million in 2004. Our operating income and EBITDA increased in 2004 from $84.7 million and $132.0 million, respectively, in 2003, primarily due to a 31% increase in production volumes and higher realized natural gas and oil prices. Our operating income and EBITDA increased in 2003 from $36.0 million and $83.1 million, respectively, in 2002, primarily due to higher realized natural gas and oil prices and slightly higher production volumes. We refer you to "Business Overview -- Other Items -- Reconciliation of Non-GAAP Measures" in Item 1 of Part I of this Form 10-K for a reconciliation of EBITDA with our net income. In addition to our core operations, we actively seek to develop new conventional exploration proje cts as well as unconventional plays (which we refer to as New Ventures) with significant exploration and exploitation potential.

        Our estimated proved natural gas and oil reserves were 645.5 Bcfe as of December 31, 2004, up from 503.1 Bcfe at year-end 2003 and 415.3 Bcfe at year-end 2002. The increase in total reserves over the past three years is primarily due to the accelerated development of our Overton Field in East Texas, our successful conventional drilling program in the Arkoma Basin, and development of a new field in the Permian Basin. Our year-end 2004 reserves had an after-tax PV-10 value, or standardized measure, of $892.3 million, up from $716.4 million at year-end 2003 and $501.6 million at year-end 2002. We refer you to Note 6 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas and oil reserves. Approximately 92% of our proved reserves were natural gas and 83% were classified as proved developed. We operate approximately 76% of our reserves, based on our PV-10 value, and our average proved reserves-to-production ratio, or average reserve life, approximated 11.9 years at year-end 2004. Sales of natural gas production accounted for 92% of total operating revenues for this segment in 2004 as compared with 91% in 2003 and 88% in 2002. Natural gas production has increasingly generated a substantial portion of total operating revenues as a result of the natural gas focus of our capital investments in the past three years.

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        In 2004, we replaced 365% of our production volumes by adding 197.2 Bcfe of proved natural gas and oil reserves at a finding and development cost of $1.43 per Mcfe, including a net downward reserve revision of 12.7 Bcfe. In 2003 and 2002, our reserve replacement ratios were 313% and 215%, respectively, and our finding and development costs were $1.33 per Mcfe and $0.99 per Mcfe, respectively, including a net downward reserve revision of 15.5 Bcfe in 2003 and a net upward reserve revision of 2.5 Bcfe in 2002. The negative reserve revisions during 2004 were primarily due to slightly higher decline rates related to some of the wells in our Overton Field in East Texas, while negative revisions in 2003 were primarily due to poorer-than-expected well performance related to our South Louisiana properties. Revisions during 2002 were positive primarily due to higher year-end commodity prices. The increase in our reserve replacement ratio during this tim e period is primarily due to increased success of our drilling programs in finding new natural gas and crude oil reserves and an increasing level of capital expenditures. The increase in our finding and development costs primarily reflects the general increase in material costs and oil field service costs to drill and complete wells in our key operating areas, as well as approximately $14.0 million and $11.0 million invested during 2004 and 2003, respectively, in acquiring leasehold positions in our Fayetteville Shale play. For the period ending December 31, 2004, our three-year average reserve replacement ratio was 305%, and our estimated three-year average finding and development cost was $1.30 per Mcfe, including reserve revisions.

        Our reserve replacement ratio during 2004, excluding the effect of reserve revisions, was 388%, compared to 351% in 2003 and 209% in 2002. Our finding and development cost, excluding revisions, was $1.34 per Mcfe in 2004, compared to $1.18 per Mcfe in 2003 and $1.02 per Mcfe in 2002. The increase in our finding and development costs during this time period were primarily due to higher costs for drilling and other field services. Excluding reserve revisions, these three-year averages were 324% and $1.23 per Mcfe, respectively.

        The following table provides information as of December 31, 2004 related to proved reserves, well count, and net acreage, and 2004 annual information as to production and capital expenditures, for each of our core operating areas, for our New Ventures and overall:

        Arkoma Basin. 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." In recent years, we have expanded our activity in the Arkoma Basin south and east of the traditional Fairway area and into the Oklahoma portion of the basin. Our drilling program in the Arkoma Basin is comprised of both conventional and unconventional activities. We refer to our drilling program targeting stratigraphic Atokan-age objectives in Oklahoma and in the Fairway and in the Ranger Anticline area located south of the Fairway in Arkansas as our "conventional Arkoma" drilling program. Our Fayetteville Shale play represents our entire unconventional drilling program in the Arkoma Basin. At December 31, 2004, we had approximately 247.0 Bcf of natural gas reserves in the Arkoma Basin, representing approximately 38% of our total reserves, up from 211.7 Bcf at year-end 2003 and 188.7 Bcf at year-end 2002.

        Conventional Arkoma Program. Our conventional Arkoma drilling program continues to provide a solid foundation for our E&P program and represents a significant source of our production and reserves. Approximately 239.5

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Bcf of our reserves at year-end 2004 were attributable to our conventional Arkoma wells. During 2004, we participated in 70 wells with 55 producers, 9 dry holes and 6 wells in progress at year-end, resulting in an 86% drilling success rate while adding 43.4 Bcf of gas reserves at a finding and development cost of $1.23 per Mcf, excluding a net upward reserve revision of 4.5 Bcf, or $1.11 per Mcf including such revision. This compares to finding and development costs of $1.14 per Mcf in the basin in 2003 and $0.99 per Mcf in 2002, excluding net upward reserve revisions of 13.1 Bcf and 4.4 Bcf, respectively. Including such revisions, finding and development costs would have been $0.79 per Mcf in 2003 and $0.80 per Mcf in 2002. The increase in our finding costs during this time period was primarily due to higher costs for drilling and other oil field services. Our gas production from our conventional drilling program in the Arkoma Basin was 20.1 Bcf during 2004, or approximately 55 MMcf per day, compared to 18.9 Bcf in 2003 and 19.8 Bcf in 2002. The increase in production in 2004 was primarily due to a greater number of wells drilled in the basin and higher production volumes from our Ranger Anticline area. The decrease in production during 2003 from 2002 levels was primarily due to the natural decline in our properties, offset somewhat by production from new wells drilled in the year.

        Our conventional activities in the Arkoma Basin continue to generate a significant amount of our cash flow. With three-year average finding and development costs of $1.15 per Mcf, excluding revisions (or $0.93 per Mcf including revisions), and three-year average production, or lifting, costs of $0.43 per Mcf (including production taxes), our cash margins from our conventional drilling program in the Arkoma Basin are very attractive. Lifting costs continued to be low during 2004 at $0.48 per Mcf (including production taxes), compared to $0.46 per Mcf in 2003 and $0.30 per Mcf in 2002. While lifting costs from our conventional drilling program in the basin have increased primarily due to higher oil field service costs, we continue to be one of the lowest cost producers in the industry.

        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 2004, we completed 16 wells out of 19 drilled in the Fairway, adding 2.4 Bcf of new natural gas reserves. The average working interest in our 2004 Fairway wells drilled is 44% and our average net revenue interest is 38%. We intend to drill up to 18 conventional wells and perform at least 29 workovers in the Fairway portion of the Arkoma Basin in 2005.

        In recent years, we have extended our development program into the Oklahoma portion of the Arkoma Basin, and into other areas of the basin in Arkansas that have been lightly explored to date. Since 2002, we have significantly increased our drilling activity in our Ranger Anticline prospect area, located at the southern edge of the Arkansas portion of the basin, largely as a result of continued drilling success and favorable regulatory developments. In 2003, Act 964 was passed by the Arkansas legislature providing operators with the opportunity to pursue multi-well development of original 640-acre units. Also during 2003 we received regulatory approval to downspace a large portion of the Ranger Anticline area to 80-acre spacing. In 2004, we obtained further regulatory approval to reduce well spacing from 80-acres per well to a minimum distance of 560 feet between wells at Ranger, which provides more efficient development of the field and greate r flexibility to site the wells in the most geologically advantageous locations.

        We drilled our first successful well at Ranger in 1997, and through year-end 2004, we successfully drilled 43 out of 50 wells at Ranger, adding 62.8 net Bcf of reserves at a finding cost of $0.72 per Mcf, including reserve revisions. During 2004, we successfully completed 20 out of 22 wells, which added 29.8 Bcf of new reserves at a finding and development cost of $0.82 per Mcf, including revisions. At December 31, 2004, gross production from the field was 23.4 MMcf per day, compared to 7.6 MMcf per day at year-end 2003 and 2.3 MMcf per day at year-end 2002. Our wells at Ranger typically target the Upper and Lower Borum tight gas sands between 5,000 and 8,000 feet in depth. These wells cost approximately $1.0 million to drill and complete, have average initial production rates of approximately 1.8 MMcf per day when successful, and have average estimated ultimate gross reserves of 1.8 Bcf per well. Our average working interest in the 43 successful wells drilled through December 31, 2004 is 81% and our average net revenue interest is 66%.

        Our growing understanding of the geology at Ranger indicates that the productive area is larger than originally thought in 1997. In each of the last two years, we increased our acreage position at Ranger and, as of December 31, 2004, we held approximately 7,700 gross developed acres and 43,500 gross undeveloped acres. Our average working interest in our gross undeveloped acreage position at Ranger is 60%. We believe that Ranger holds significant future development potential. In 2005, we intend to drill up to 43 wells in this area and we estimate that there could be over 100 additional locations to drill in 2006 and beyond.

        Our strategy for the conventional Arkoma Basin drilling program is to continue our development drilling and workover programs at a level that maintains our production and reserve base. In 2005, we plan to invest approximately $59.3 million in the conventional Arkoma program to drill approximately 86 wells and perform at least 31 workover projects.

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        Fayetteville Shale Play. In August 2004, we announced that we are testing a new unconventional shale gas play on the Arkansas side of the Arkoma Basin, which we refer to as the Fayetteville Shale play. We are drilling test wells targeting the Fayetteville Shale, an unconventional gas reservoir, ranging in depths from 1,500 to 6,500 feet. The Fayetteville Shale is a Mississippian-age shale that is the geologic equivalent of the Caney Shale found on the Oklahoma side of the Arkoma Basin and the Barnett Shale found in north Texas.

        Our Fayetteville Shale play is the outgrowth of extensive internal geologic analysis that began in 2002 when we recognized an incongruity in the amount of gas production that was attributed to completions in the Wedington Sandstone. The Wedington Sandstone is embedded within the Fayetteville Shale sequence. In several incidents within the Fairway area, more gas was being produced than would have been expected based on the Wedington's thickness, petrophysical properties and aerial extent. In 2002, we undertook and completed an extensive geologic study to understand the distribution of the Fayetteville Shale throughout the basin, including its thickness, burial history and thermal maturity. We also obtained Fayetteville Shale core samples associated with the drilling of development wells in our conventional Fairway drilling program. The samples were analyzed for the critical shale properties necessary for successful shale gas plays. The analyses indicated encouraging data relative to total organic content, which ranged from 4.0% to 9.5%, thermal maturity, which ranged from 1.5 to 4.0 and total gas content, which ranged from 60 to 220 standard cubic feet, or scf, per ton, which compared favorably to other productive shale gas plays, including the Barnett. The analyses, along with an extensive geologic mapping project, led us to believe that the Fayetteville Shale represented a legitimate objective reservoir and in early 2003 we commenced acquiring a land position. By December 31, 2003, we had acquired 343,351 net undeveloped acres in the play area, which we disclosed as "New Ventures" acreage in our 2003 annual report on Form 10-K. In June 2004, we initiated a pilot well drilling program in the Fayetteville Shale and 21 vertical wells had been drilled as of December 31, 2004. The test wells were drilled in five pilot areas located in Franklin, Conway, Van Buren and Faulkner counties in Arkansas. The Fayetteville Shale was present as predicted by prior mapping across the tested area and appears to be laterally extensive, ranging in thickness from 50 to 325 feet. At December 31, 2004, ten wells had been placed on production and were producing at rates ranging from 100 to 500 Mcf per day, with the longest production history of approximately 150 days. Of the remaining wells drilled, six were in various stages of testing or completion, two were awaiting pipeline connection with production test rates prior to shut-in of 325 and 1,320 Mcf per day, and three were shut-in as they appear to be marginal performers. Of the 21 wells drilled through December 31, 2004, 19 wells were completed using nitrogen foam fracture stimulation treatm ents of various sizes, and two wells were completed with slick-water fracture treatments. We have seen significant variability in well performance, and will continue to pursue optimization of our fracture stimulation treatments to maximize well performance.

        In 2004, we invested approximately $27.9 million in our Fayetteville Shale play, which included $11.6 million in capital for drilling 21 wells, $14.0 million for leasehold acquisition, and $2.3 million for other capitalized costs. We increased our leasehold position to 557,149 net acres in the undeveloped play area at December 31, 2004. In addition, we control approximately 125,000 net developed acres in our traditional "Fairway" area of the basin that is held by conventional production. Total proved gas reserves booked in the play in 2004 totaled 7.5 Bcf from a total of 20 wells, 10 of which were classified as proved, undeveloped locations, for an average estimated ultimate recovery per well of 430,000 Mcf (375,000 Mcf net).

        Based on results achieved to date and assuming that the current oil and gas price environment continues to be favorable, we expect to allocate up to $100.2 million of our 2005 E&P capital to our unconventional Fayetteville Shale play, which would include drilling up to approximately 160 to 170 wells. Our drilling program with respect to our Fayetteville Shale play is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation, the extent to which we can replicate the results of our most successful Fayetteville Shale wells on our other Fayetteville Shale acreage as well as the gas and oil commodity price environment. We refer you to "Risk Factors -- Our drilling plans for the Fayetteville Shale play are subject to change." As previously noted, as of December 31, 2004, we had only drilled 21 wells in areas that represent a very small sample of our large acreage position. We continue to gather data about our prospects in the Fayetteville Shale, and it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.

        East Texas. Our East Texas operations are primarily located in the Overton Field in Smith County, Texas, which produces from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet. Overton provides a low-risk, multi-year drilling program with significant production and reserve growth potential based on the potential level of infill drilling. Our original interest in the Overton Field (which was approximately 10,800 gross acres) was acquired in April 2000 for $6.1 million. Our interest now totals approximately 24,400 gross acres, our average working interest in the Overton Field is 96% and average net revenue interest is 77%.

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        When we acquired the field in April 2000, it 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. In 2003, we received regulatory approval from the Texas Railroad Commission to allow downspacing at Overton to optional 80-acre spacing. We also received approval in 2003 to drill four wells at locations that were effectively 40-acre spaced wells. Of the four test wells drilled at 40-acre spacing, three wells indicated pressures near original reservoir pressures and one showed partial depletion. Data from the four 40-acre spaced wells indicated that a significant portion of the field would likely require 40-acre spaced wells to adequately develop the field. During the first quarter of 2004, we received regulatory approval to allow downspacing at Overton to optional 40-acre spacing.

        In 2004, we drilled and completed a total of 83 wells, of which 35 were 40-acre spaced wells. This compares to 57 wells drilled and completed in 2003 and 18 wells in 2002. We have experienced a 100% success rate at Overton since we began our development drilling program in 2001. Daily gross production at the Overton Field has increased from approximately 2.0 MMcfe in March 2001 to approximately 90.0 MMcfe at year-end 2004 resulting in net production of 21.8 Bcfe during 2004, compared to 13.6 Bcfe in 2003 and 5.9 Bcfe in 2002. New wells drilled in the field during 2004 averaged approximately $1.6 million to drill and complete, had average initial production rates of approximately 2.9 MMcfe per day and had average estimated ultimate gross reserves of 2.0 Bcfe per well. Our average production costs (including production taxes) were $0.50 per Mcfe in 2004, compared to $0.45 per Mcfe in 2003 and $0.40 per Mcfe in 2002. The increases in our unit p roduction costs were primarily due to higher production taxes resulting from higher realized commodity prices, partially offset by increased production.

        Our proved reserves in East Texas increased to 299.1 Bcfe at year-end 2004, or 47% of our total reserves, of which 296.6 Bcfe of reserves were in our Overton Field. Our reserves at Overton were up significantly from 196.3 Bcfe at year-end 2003 and 111.0 Bcfe at year-end 2002, primarily due to the acceleration of our infill drilling program in early 2003. We invested approximately $148.0 million at the Overton Field during 2004 which resulted in proved reserve additions of 142.2 Bcfe at a finding and development cost of $1.04 per Mcfe, excluding a net downward reserve revision of 19.2 Bcfe, or $1.20 per Mcfe including such revision. Our finding and development costs were $0.95 per Mcfe excluding a net downward reserve revision of 3.7 Bcfe (or $0.98 per Mcfe including such revision) in 2003 and $0.60 per Mcfe excluding a net upward reserve revision of 2.8 Bcfe (or $0.57 per Mcfe including such revision) in 2002. The average estimated ultimate rec overy of gas and oil reserves from new wells completed in 2004 was approximately 2.0 gross Bcfe per well, compared to 2.2 gross Bcfe per well in 2003 and 2.9 gross Bcfe per well in 2002. The decrease in gross reserves per well over this time period is primarily due to our drilling of locations with the highest anticipated ultimate recovery earlier in our development program and we expect that this trend will continue with future development wells in the field. Our finding cost increased in 2004 primarily due to slightly lower reserves per well combined with higher costs for drilling and other oil field services. Our finding cost in 2003 increased primarily due to the installation of additional field production facilities and the acquisition of producing properties for future development.

        In 2005, we plan to invest approximately $147.6 million in East Texas and drill approximately 96 wells, of which approximately 80 wells are planned at Overton. Based on reasonable gas price assumptions and our investment hurdle rate, it appears that our drilling program at Overton could be extended through 2006. With a NYMEX gas price of $5.00 per Mcf, we estimate that approximately 37 wells could be drilled beyond our 2005 drilling program. Alternatively, with a NYMEX gas price of $6.00 per Mcf, we estimate that approximately 92 wells could be drilled beyond our 2005 drilling program.

        Permian Basin. We have had an active drilling program since 1997 in the Permian Basin, which is primarily located in west Texas and southeast New Mexico. In July 2004, we acquired additional working interest in our River Ridge field for $14.2 million, which consolidated our position in this property and allowed us to gain additional development opportunities. The acquisition increased our working interest in an existing producing well to 50% from 12.5%, and gave us a 50% working interest in another well in which we previously held no interest. The acquired interest added approximately 5.8 net Bcfe in proved reserves. We subsequently participated in drilling three additional wells in the field, bringing the well count to five, and all were producers. Net production from the field during 2004 was 3.2 Bcfe and total net proved reserves as of December 31, 2004, were approximately 11.0 Bcfe, bringing our overall finding and developme nt cost in the field to $1.63 per Mcfe, excluding reserve revisions (or $1.64 per Mcfe including negative reserve revisions of 0.1 Bcfe). We hold a 50% working interest in this field.

        At December 31, 2004, our proved reserves in the Permian Basin were 60.8 Bcfe, compared to 55.6 Bcfe in 2003 and 57.1 Bcfe in 2002. Our production in the basin during 2004 was 7.1 Bcfe, or approximately 19 MMcfe per day, compared to 4.2 Bcfe in 2003 and 4.9 Bcfe in 2002. The increase in reserves and production from 2003 was primarily due to increased volumes from our River Ridge discovery and subsequent development of that field during 2004. Our production costs (including production taxes) averaged $1.21 per Mcfe, compared to $1.15 per Mcfe in 2003 and $1.13 per

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Mcfe in 2002. The increases in production costs were primarily due to increased production taxes resulting from higher gas and oil commodity prices. Our finding and development cost in the Permian in 2004 was $2.62 per Mcfe excluding a net upward reserve revision of 2.6 Bcfe, or $2.09 per Mcfe including such revision. Our finding and development costs were $0.95 per Mcfe excluding a net downward reserve revision of 7.1 Bcfe (or $3.44 per Mcfe including such revision) in 2003 and $3.57 per Mcfe excluding a net downward reserve revision of 0.1 Bcfe (or $3.85 per Mcfe including such revision) in 2002. The increase in finding cost in 2004, excluding revisions, was primarily due to the acquisition of additional working interest in our River Ridge discovery while the decrease in finding cost during 2003 was primarily due to the initial discovery itself.

        In 2004, we invested $27.0 million, drilling 14 wells, of which 8 were successful, resulting in reserve additions of 10.3 Bcfe. In 2005, we plan to invest approximately $4.8 million in our Permian Basin program to drill approximately 12 exploration and exploitation wells.

        Gulf Coast. Our Gulf Coast operations are located in the onshore areas of Texas and Louisiana. Since our first discovery in December 1999, the efforts of our exploration program have resulted in 10 successful wells out of 23 wildcats drilled in South Louisiana. We have not had a significant discovery in South Louisiana since 2001. In 2002 and 2003, we participated in 12 wells, 3 of which were successful. In 2004, we participated in two exploration wells in South Louisiana, one of which was successful. We own a 50% working interest in the successful well. Our proved reserves in these areas totaled 38.6 Bcfe at December 31, 2004, compared to 39.5 Bcfe at year-end 2003 and 58.5 Bcfe at year-end 2002. Approximately 14.2 Bcfe of reserves at December 31, 2004, were located in Louisiana. The decline in reserves during 2004 was primarily due to the natural decline in these properties, partially offset by 4.3 Bcfe of reserve adds fro m drilling. In 2003, we revised our reported reserve estimates for this area downward by 17.7 Bcfe primarily due to poorer-than-expected well performance related to our South Louisiana properties. Net production from this area in 2004 was 4.6 Bcfe, or approximately 13 MMcfe per day, compared to 4.5 Bcfe in 2003 and 7.5 Bcfe in 2002. The decrease in production in 2003 from 2002 was primarily due to poorer-than-expected well performance related to our South Louisiana properties. Production costs (including production taxes) averaged $1.39 per Mcfe during 2004, compared to $1.23 per Mcfe in 2003 and $1.07 per Mcfe in 2002. The increase in our unit production costs over this time period was primarily due to the decline in production volumes from these properties. In 2004, our finding and development cost was $3.65 per Mcfe, excluding reserve revisions, compared to $6.00 per Mcfe in 2003 and $3.68 per Mcfe in 2002. The relatively high finding costs during this time period was primarily due to the lack of s ignificant success in our South Louisiana exploration program over the last three years.

        In 2004, we invested $15.7 million in this area, adding 4.3 Bcfe of reserves. Our recent drilling activities in this area are not meeting our economic criteria and we are reducing our investments in the Gulf Coast to $4.8 million in 2005. While we still plan to drill up to 8 wells in the area in 2005, the majority of these wells will be developmental in nature.

        Other Exploration and New Ventures. In addition to our core operations, we actively seek to develop new conventional exploration projects as well as unconventional plays (which we refer to as New Ventures) with significant exploration and exploitation potential. We have personnel dedicated to the research and identification of active and potential plays, focusing on both conventional exploration plays and unconventional plays (including coal bed methane, shale gas and basin-centered gas) as well as the technological aspects such as horizontal drilling and fracture techniques. New prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria. As of December 31, 2003, we had acquired 345,310 net undeveloped leasehold acres in new project areas for approximately $11.0 million, which we disclosed as "New Ventures" acreage in our 2003 annual report on Form 10-K. Of these 345,310 net undeveloped acres, approximately 343,351 acres related to our Fayetteville Shale play in Arkansas, which is now part of our Arkoma operations. In early 2004, we acquired 95,000 net acres in a coal bed methane play located in the Crazy Mountain Basin in Montana and drilled a test well to determine its producibility. We determined that the coal resource was too thin to be commercially developed and are not pursuing this coal bed methane play any further. During 2004, we also acquired approximately 47,596 acres in areas of the United States outside of our core operating areas in connection with other unconventional natural gas and oil plays that we are pursuing.

        In 2004, we invested approximately $1.5 million in New Ventures, excluding the Fayetteville Shale play, which included drilling one exploration well relating to the abandoned coal bed methane play. In 2005, we plan to invest approximately $18.1 million in exploration projects and $4.2 million in New Venture projects, including drilling up to 14 exploration and unconventional wells in the continental United States.

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        In 2004, we purchased 5.8 Bcfe of proved reserves for $14.2 million at an average cost of $2.45 per Mcfe. Almost all of this investment related to the acquisition of additional working interest in our River Ridge discovery in Lea County, New Mexico.

        In 2003, we purchased an aggregate of 1.1 Bcfe of proved reserves for $3.0 million, at an average cost of $2.73 per Mcfe. The transactions included working interests in our core Arkoma Basin, Overton Field and Permian Basin producing areas. The average cost per Mcfe was higher than for prior acquisitions due to the potential existence of future drilling opportunities beyond the existing production.

        In 2002, we purchased 6.6 Bcfe of proved reserves for $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 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.

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

        We invested a total of $282.0 million in our E&P program and participated in drilling 204 wells during 2004. Of these drilled wells, 166 were successful, 14 were dry and 24 were still in progress at year-end. Our investments were balanced between our core areas of operations, with approximately $53.2 million invested in our conventional Arkoma Basin drilling program, $156.7 million in East Texas, $27.0 million in the Permian Basin, and $15.7 million in the Gulf Coast. In addition, we invested approximately $27.9 million in our Fayetteville Shale play and $1.5 million in our New Ventures. Of the $282.0 million invested, approximately $20.1 million was invested in exploratory drilling, $208.7 million in development drilling and workovers, $21.1 million for leasehold acquisition and seismic expenditures, $14.2 million for producing property acquisitions, and $17.9 million in capitalized interest and expenses and other technology-related expenditures. During 2003, we invested a total of $170.9 million in our E&P business and participated in 139 wells, and in 2002 we invested $85.2 million and participated in 65 wells. The increases in capital investments and wells drilled during this time was primarily due to the acceleration of our development drilling program at our Overton Field, an increase in conventional drilling activity at our Ranger Anticline area in the Arkoma Basin, and leasehold investments and drilling in our Fayettevi lle Shale play.

        In 2005, we intend to allocate up to $339.0 million for our E&P capital budget, an increase of approximately 20% over our capital investment level in 2004. We continue to be focused on our strategy of adding value through the drillbit, as over 80% of our 2005 E&P capital is allocated to drilling. Our investments in 2005 will primarily be focused on our lower-risk, high-return conventional drilling programs in East Texas and the Arkoma Basin. During 2005, we expect to invest approximately $147.6 million in East Texas and $59.3 million in our conventional Arkoma Basin drilling program. Based on results achieved to date and assuming that the oil and gas price environment continues to be favorable, we also expect to allocate up to $100.2 million of our 2005 E&P capital to our unconventional Fayetteville Shale play. The remainder of our E&P capital will be allocated to exploration and exploitation in the Permian Basin ($4.8 million), the onshore Gulf Coast ($4.8 million) and to other exploration projects ($18.1 million) and New Venture projects ($4.2 million). Of the up to $339.0 million allocated to the E&P capital budget, approximately $256.6 million will be invested in development drilling, $24.5 million in exploratory drilling, $26.8 million for land and seismic, $24.0 million in capitalized interest and expenses and $7.1 million in equipment, facilities 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 2005.

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        Other revenues and operating income for 2004 and 2003 also included pre-tax gains of $4.5 million and $3.1 million, respectively, related to the sale of gas-in-storage inventory. This compares to virtually no revenue or operating income in 2002 from the sale of gas-in-storage inventory.

        Our daily natural gas equivalent production averaged 148.2 MMcfe in 2004, up 31% from 112.7 MMcfe in 2003. Our daily natural gas equivalent production was 109.8 MMcfe in 2002. Our natural gas production was 50.4 Bcf in 2004, compared to 38.0 Bcf in 2003 and 36.0 Bcf in 2002. We also produced 618,000 barrels of oil in 2004, compared to 531,000 barrels of oil in 2003 and 682,000 barrels in 2002. Our gas production has increased since 2002 primarily due to the acceleration of our development drilling program at our Overton Field in East Texas, which predominantly produces gas. Our oil production increased in 2004 due to increased oil production from our River Ridge discovery. Our oil production declined in 2003 due to the sale of our Mid-Continent properties in November 2002, which were predominantly oil producing properties. For 2005, we are targeting our total natural gas and crude oil production to be approximately 61.0 Bcfe to 63.0 Bcfe , which equates to a growth rate of approximately 13% to 17% above our 2004 production volumes.

        We realized an average wellhead price of $5.21 per Mcf for our natural gas production in 2004, compared to $4.20 per Mcf in 2003 and $3.00 per Mcf in 2002, including the effect of hedges. Our hedging activities lowered our average gas price $0.59 per Mcf in 2004, $0.95 per Mcf in 2003, and $0.11 per Mcf in 2002. Our average oil price realized was $31.47 per barrel in 2004, compared to $26.72 per barrel in 2003 and $21.02 per barrel in 2002, including the effect of hedges. Our hedging activities lowered our average oil price $9.08 per barrel in 2004, $2.94 per barrel in 2003 and $2.92 per barrel in 2002.

        Our gas sales to unaffiliated purchasers were 45.0 Bcf in 2004, compared to 32.1 Bcf in 2003 and 30.6 Bcf in 2002. Gas sales volumes to our affiliated utility subsidiary, Arkansas Western, have been fairly stable over the past three years, averaging approximately 5.5 Bcf annually. 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 82% of total E&P revenues in 2004, 86% in 2003 and 85% in 2002. In 2004, the largest unaffiliated purchaser accounted for 9% of total E&P revenues.

        Our utility subsidiary, Arkansas Western is the largest single customer for sales of our gas production. 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 10% of total E&P revenues in 2004, 12% in 2003 and 15% in 2002. SEECO's sales to Arkansas Western were 5.5 Bcf in 2004, compared to 5.9 Bcf in 2003 and 5.4 Bcf in 2002. Sales to Arkansas Western are primarily driven by the utility's changing supply requirements due to variations in the weather and SEECO's ability to obtain gas supply contracts that are periodically placed out for bids. SEECO's gas production provided approximately 40% of the utility's requirements in 2004, 41% in 2003 and 37% in 2002. We also sell gas directly to industrial and commercial transportation customers located on Arkansas Western's gas distribution systems. 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 Wes tern'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, 2004, we had hedges in place on 44.6 Bcf of 2005 gas production, 27.0 Bcf of 2006 gas production, 360,000 barrels of 2005 oil production and 120,000 barrels of 2006 oil production. Subsequent to December 31, 2004 and prior to March 3, 2005, we hedged 4.0 Bcf of 2006 gas production under costless collars with floor prices of $5.50 per Mcf and ceiling prices ranging from $7.60 to $13.50 per Mcf.  As of

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 December 31, 2004, we had hedges in place on approximately 70% to 80% of our targeted 2005 gas production and approximately 60% to 70% of our 2005 targeted oil production. We refer you to Item 7A of this Form 10-K, "Quantitative and Qualitative Disclosures About Market Risk," for further information regarding our hedge position at December 31, 2004.

        Disregarding the impact of hedges, based on the current price environment, we expect the average price received for our gas production to be approximately $0.30 to $0.50 per Mcf lower than average spot market prices, as market differentials that reduce the average prices received are partially offset by demand charges under the contracts covering our intersegment sales to Arkansas Western. Disregarding the impact of hedges, based on the current price environment, 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.

        All phases of the oil and gas industry are highly competitive. We compete for properties, reserves, and the labor and equipment required to conduct our 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.

        Sales of crude oil, condensate and gas liquids are not regulated and are made at negotiated prices. Effective January 1, 1995, the Federal Energy Regulatory Commission, or 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.